Spring 2016 · 2016-03-21 · Spring 2016 THE SAUDI ARAMCO JOURNAL OF TECHNOLOGY A quarterly publication of the Saudi Arabian Oil Company Journal of Technology Saudi Aramco Contents

Spring 2016

THE SAUDI ARAMCO JOURNAL OF TECHNOLOGYA quarterly publication of the Saudi Arabian Oil CompanyJournal of Technology

Saudi Aramco

Contents

First Application of a Sequenced Fracturing Technique to Divert Fractures in a Vertical Open Hole Completion: Case Study from Saudi Arabia 2Kirk M. Bartko, Roberto Tineo, Dr. Gallyam Aidagulov, Ziad Al-Jalaland Andrew Boucher

Investigation of the Stability of Hollow Glass Spheres in Fluids and Cement Slurries for Potential Field Applications in Saudi Arabia 12Dr. Abdullah S. Al-Yami, Mohammed B. Al-Awami and Dr. Vikrant B. Wagle

Impact of Multistage Fracturing on Tight Gas Recovery from High-Pressure/High Temperature Carbonate Reservoirs 20Dr. Zillur Rahim, Adnan A. Al-Kanaan, Dr. Hamoud A. Al-Anazi,Rifat Kayumov and Ziad Al-Jalal

Development and Field Trial of the Well Lateral Intervention Tool 28Dr. Mohamed N. Noui-Mehidi, Abubaker S. Saeed, Haider Al Khamees and Mohamed Farouk

Directional Casing while Drilling (DCwD) Reestablished as Viable Technology in Saudi Arabia 36Germán A. Muñoz, Bader N. Al-Dhafeeri, Hatem M. Al-Saggaf,Hossam Shaaban, Delimar C. Herrera, Ahmed Osman and Locus Otaremwa

Preliminary Test Results of an Eco-Friendly Fluid Loss Additive Based on an Indigenous Raw Material 48Dr. Md Amanullah, Dr. Jothibasu Ramasamy and Mohammed K. Al-Arfaj

Pioneering Utilization of Fluid Cryogenics in Mimicking Shutoff Barrier Characteristics 55Nawaf D. Al-Otaibi, Nelson O. Pinero, Ibrahim A. Al-Obaidi and Carlo Mazzella

Advancements in Well Conformance Technologies Used in a Major Field in Saudi Arabia: Case Histories 61Ahmed K. Al-Zain, Mohammed A. Al-Atwi, Ahmed A. Al-Jandal, Rami A. Al-Abdulmohsen and Hashem A. Al-Ghafli

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ABSTRACThydraulic fractures in long vertical open hole intervals usingthis two-step diversion process for sequenced fracturing. Theability to do this consistently — and predictably — can pro-vide a practical, efficient and cost-effective preferred solutionthat does not exist today for completing and fracturing similarzones that are traditionally bypassed, resulting in increasedproduction and reserves.

INTRODUCTION

The well that was considered for the first application of a se-quenced fracturing technique in a vertical well was an explo-ration well located in the northern part of Saudi Arabia. Thewell originally targeted a shallow formation but was drilleddeeper for appraisal of the deeper horizons. Six targets of in-terest were selected across a tight, heterogeneous sandstonelayer of the Q formation. These targets spanned a 552 ft verti-cal open hole section where previous experience had showedlarge stress variations in the layers and natural fractures. Thelarge stress variations would require individual fracture treat-ments to ensure stimulation of each sand package. Not onlywas this option costly, but the current completion pressurelimitations would not be adequate to perform a cased holefracture treatment.

A decision was made to move forward with an open holecompletion, based on work by Chang et al. (2014)1, whodemonstrated — through a series of open hole block tests —that a fracture initiation position within an open hole can betargeted using a weak point cut into a rock. It was furtherdemonstrated that two independent transverse fractures couldbe initiated from two notches placed in a single open hole hori-zontal wellbore. Aidagulov et al. (2015)2 developed a modelthat predicts the orientation, position and pressure at which afracture will initiate from the notched open hole, which builtthe confidence needed to perform a hydraulic fracture treat-ment in a high stress area with pressure limitations due to thecompletion.

The limitation of the work cited here is that it was devel-oped for horizontal wells where the in situ stress contrast isrelatively constant throughout the lateral, making it simpler toinitiate and extend multiple fractures because the pressures arerelatively constant in a homogeneous wellbore. In a vertical

A unique sequenced fracturing technique using formationnotching and degradable diversion pills was applied for thefirst time in a vertical open hole completion to stimulate multi-ple pay intervals in a well in the “Q” sandstone formation ofSaudi Arabia.

The challenge — to divert fractures in a vertical open hole— is made more difficult by the large fracture surface area is incontact with the wellbore. A robust, efficient and repeatabletwo-step technique was implemented to provide the diversionand controlled breakdown of higher stressed sections of the interval. The first step used a specialized jetting nozzle to createcircular notches and weaken the formation at target depths.The second step involved the pumping of a small volume of acomposite fluid made up of degradable non-damaging fiberand multimodal particles that bridge at the fracture face,which would divert the remainder of the treatment to understim-ulated sections of the interval.

The target for this well was a shallower formation, due tocompletion pressure limitations while fracturing. This left sixpay intervals spread across the tight, heterogeneous sandstonelayers of the Q formation, spanning a single 552 ft verticalopen hole section. Previous experience showed large stressvariations in the layers with contained fractures, so fracturingall pay intervals would require separate treatments for the interval. After notching the pay intervals to reduce breakdownpressures, each interval was fractured with three proppantramps separated by two diversion pills in the span of eighthours, improving efficiency more than threefold. Diversionwas confirmed by: (1) Pressure increases of 380 psi and 500psi, respectively, when the pills landed on formation, (2) In-creasing the trend of the initial shut-in pressures (ISIPs)throughout the treatment, resulting in 1,270 psi of net pressuregain, and (3) Comparison of post-diagnostic injection test tem-perature log data with post-fracture neutron log data, showingwhere nonradioactive traceable proppant was placed, includ-ing into at least three pay intervals not broken down duringthe injection test. Post-treatment production expectations weremet and confirmed with a well test.

This article will present the design, execution and evalua-tion methodology, and challenges that were overcome to divert

First Application of a Sequenced FracturingTechnique to Divert Fractures in a VerticalOpen Hole Completion: Case Study fromSaudi ArabiaAuthors: Kirk M. Bartko, Roberto Tineo, Dr. Gallyam Aidagulov, Ziad Al-Jalal and Andrew Boucher

2 SPRING 2016 SAUDI ARAMCO JOURNAL OF TECHNOLOGY


wellbore, one needs to consider that the stress increases as onemoves down the wellbore due to the changing overburdenpressure. Therefore, to compensate for the changing stress gra-dient, a diverter would be required to move the fluids fromzone to zone once the fracture is initiated. Adil et al. (2014)3

demonstrated in a 616 ft open hole — within a thick homoge-neous rock layer — that diversion could be accomplishedthrough a series of diversion stages where pressure increaseswere observed when the diverter entered the formation. Thiswork, however, did not show any post-diagnostics that demon-strated the effectiveness of the treatment coverage.

The diverter pill needs to be effective in diverting high-pres-sure fluids, needs to withstand bottom-hole temperatures(BHTs) and needs to dissolve over time, leaving no residual be-hind. The selected sequence diverting fluid was a multimodalsize distribution of particulates and fibers. The material is ef-fective up to 330 °F. The material dissolves within three hours,leaving no residual materials behind.

Other challenges included testing the integrity of the 7”shoe during fracturing operations, of the cement plug that iso-lated the non-reservoir rock below the zone of interest, and ofthe formation during fracturing and cleanup of the well.

RESERVOIR DESCRIPTION

The Q formation is a laminated quartz sandstone reservoirwith porosity up to 15% from the dissolution of calcite ce-ment. The tighter intervals have a clay-bound matrix and arequartz cemented fill. There appears to be moveable water inthe lower porosity intervals, and gas shows appear throughoutthe reservoir. The Q formation is highly laminated and hetero-geneous, showing a large stress contrast between layers — butnot exceeding 1,000 psi. Petrophysical interpretation suggestedsix main target layers, which were designed to be stimulatedwith three fracture stages. Figure 1 is the open hole log for thezone of interest.

FRACTURE INITIATION FROM NOTCH

The fact that operators have limited or no control of the posi-tions and orientations of initiated fractures represents one ofthe major challenges encountered in hydraulic fracturing oflong open hole wellbore sections. Indeed, the hydraulic frac-ture initiates at location(s) along the wellbore subjected to thelowest in situ stresses, surrounded by weaker rock and/orcrossed by a natural fracture — all factors that are out of theoperator’s control. One of the ways to “force” the hydraulicfracture to initiate at the target depth is to mechanicallyweaken the formation at that point. A circular notch — or360° perforation — cut into the wellbore wall in a transversedirection can play a role in creating such a weak point, Fig. 2.The notch amplifies the particular tensile stress components inthe rock and so lowers the fracture initiation pressures withinthe region of the wellbore near the notch. This circular notch

SAUDI ARAMCO JOURNAL OF TECHNOLOGY SPRING 2016 3

can be made by a high-pressure liquid jet or mechanical cutterplaced on the rotating head of the downhole tool.

Chang et al. (2014)1 conducted a lab investigation of the effect of circular and semicircular transverse notches on theinitiation of hydraulic fractures from an open hole drilled in thedirection of minimal far-field stress. This setup can be relatedto the process of stimulating a horizontal wellbore drilledalong the minimal horizontal stress direction under the normalstress regime. The experiments repeatedly demonstrated thattwo transverse fractures initiated from two notches placed in asingle open hole interval — provided that the notches were cutdeep enough into the rock. For the experimental conditionsconsidered, it was found that notches had to be at least onewellbore diameter deep to ensure transverse fracture initiation.Otherwise, the fractures were initiated longitudinally and required higher breakdown pressures.

Aidagulov et al. (2015)2 proposed the model that capturesthe observed dependence of fracture orientation direction on

Fig. 1. Open hole log over the zone of interest.

Fig. 2. Schematic of the open hole with a circular notch (360° perforation), alongwith the hoop (σϴϴ) and axial (σZZ) stress components at the surface of thewellbore and notch tip. The σϴϴ stress component opens a longitudinal fracture,whereas the σZZ stress component opens a transverse fracture along thecorresponding dashed line.


• Tensile strength, T0 = 2,500 psi.

• Far-field stresses:

o Horizontal maximum, SHMax = 8,200 psi (SHMax_g =0.75 psi/ft).

o Horizontal minimum, Shmin = 7,300 psi (Shmin_g = 0.68 psi/ft).

o Vertical, SV = 12,100 psi (SV_g = 1.1 psi/ft).

• Pp = 4,400 psi.

The following geometrical parameters for the notch andwellbore were:

• Wellbore diameter, Dw = 57⁄8”.

• Notch:

o Wn = (3/16)*Dw ≈ 1.1”.

o Dn = Dw = 57⁄8”.

• SAMTS averaging length, davg = 1”.

According to the 3D model simulations for these syntheticcase parameters, a transverse notch does not promote initia-tion of a transverse fracture, Fig. 3. Only the initiation of lon-gitudinal fractures is realistic under such high contrast betweenvertical and horizontal effective stresses: 7,700 psi vs. 2,900psi. It should be noted that as this well is directed along themaximal (vertical) stress, longitudinal fracture orientation isalso preferred by the far-field stresses.

notch depth, Dn. In that model, the notch has a round end (U-shape) and has a width, Wn, which is a certain portion of thewellbore radius, Rw, Fig. 2. These assumptions about thenotch geometry match well with the actual shape of notchesobserved in the lab tests. The model prediction is based on the3D boundary element method (BEM) elastic analysis ofstresses near the wellbore and the notch that are caused by theapplication of far-field stresses and wellbore pressure, Pw. Lon-gitudinal and transverse fracture initiation is then governed bythe hoop, σθθ, and axial, σzz, tensile stress concentrations, re-spectively.

Whether or not a particular stress component causes the ini-tiation of a fracture is decided based on the fracture criterionfor the rock. The experimental results were matched with themodel using the nonlocal fracture criterion based on the stressaveraging technique (SAMTS) and allowing for the microstruc-tural scale of the rock, davg. It was demonstrated, starting fromthe given notch depth, that the σzz stress concentration at thenotch tip met the fracture criterion earlier, i.e., at lower Pw,than the hoop stress concentration at the wellbore wall, whichresults in transverse fracture initiation. Next, we applied thismodel to evaluate the effect of the notch on the fracturingstimulation of the well under study.

The fracture initiation model proposed2 assumes nonporousand impermeable rock, and it does not include formation porepressure, Pp. To apply this “dry rock model” to the real fieldcase, the Pp must be taken into account. The simplest way oftaking into account the effect of Pp on hydraulic fracture initi-ation is by assuming that over the course of pressure buildup,fracturing fluid does not penetrate into the rock, which is validfor low permeability rock and/or fast injection. As a result, thePp in the surrounding rock does not change and remains con-stant during pressurization4. In this case, all the formulas be-hind the stress analysis of the dry rock model are also valid foreffective stress: . In contrast to the total stress,

, effective stress, , represents the load borne by the rockmatrix and so is used in fracture criteria for porous saturatedrock. The poroelastic coefficient, , is provided as a part ofthe mechanical earth model, but is often set to 1 when used forfailure predictions. Therefore, under these assumptions, thedry rock model can still be applied for this case of saturatedrock, but with the far-field stresses replaced by the effectiveones. As a result, the model will provide fracture initiationpressure in terms of wellbore overbalanced pressure:

. In the absence of a notch, this approach isequivalent to the classical and widely used Hubert-Willis esti-mate for breakdown pressure5.

Simulations were performed for the synthetic case represent-ing the conditions for the well under study at roughly a truevertical depth of 11,000 ft:

• Young’s modulus, E = 8.5E+6 psi.

• Poisson’s ratio, 𝜈 = 0.22.


,

: . In contess, , r

Fig. 3. The 3D model predicts initiation of longitudinal fracture(s) next to thetransverse notch. The red color (Sxx) is related to the concentration of the hoopstress in the zone of fracture.


The transverse notch, when pressurized with the wellborepressure, produces a zone of elevated hoop stresses within thepart of the wellbore wall close to the notch. This is clearlydemonstrated in Fig. 4, where hoop stresses were alternativelycalculated in greater detail using the axisymmetric BEM for-mulation6 for the case of equal horizontal stresses: Shmin =SHMax = 7,300 psi. Here, the cases of various notch depths areshown: no notch (blue); 25% of wellbore diameter or ¼ Dw

(green); and 100% of wellbore diameter or 1 Dw (red). In allcases, the wellbore pressure was taken to be equal to the Hu-bert-Willis breakdown pressure estimate: T0 - SHMax +3 ×Shmin-α × Pp = 12,700 psi. In the absence of the notch (bluecurve), this results in the (effective) hoop stress value at thewellbore wall being equal to the tensile strength of the rock.

One can see that for the same wellbore pressure, thenotched wellbore develops an effective hoop stress that is 8%to 20% higher than the one for the wellbore without a notch.For the notched wellbores, hoop stresses reach their maximumwithin the region close to the notch, while decaying toward thenon-notch value away from the notch. Higher hoop stressesthereby promote initiation of the longitudinal fracture first inthe zone of elevated stresses near the notch. The shallowernotch (25% of Dw) appears to induce even higher values ofhoop stresses. The extent of the area of elevated stress increasesconsistently with the notch depth. This suggests there mayeven be more chances for a longitudinal fracture to initiate, asa larger number of defects fall into the region where the stressexceeds the critical value. In this way, the region where elastichoop stress exceeds the non-notched value, i.e., tensile strengthfor this case, by 3% extends for 12” when the notch is 25% ofDw (green) and for 23” when the notch is 100% of Dw (red).

This result demonstrates a potential mechanism for control-ling the position and initiation pressure for the longitudinalfracture: placing the transverse notch in the target region ofthe open hole wellbore. This does not exclude, however, theneed for excessive validation of the proposed mechanism, asthe presented argument relies on pure elastic static stressanalysis.

ROTATING JETTING YARD TEST

The ability of hydraulic jets to penetrate the rock — makingdeep perforation tunnels7 and even breaking through severalcasing layers8 — is well-known in the industry. Tools for suchhigh-pressure jetting applications can be found among thestandard coiled tubing (CT) services. The current project re-quired the cutting of circular notches into the wellbore wall.Conceptually, this can be achieved by having the high-pressurejetting nozzle placed on the rotating head of a downhole CTtool. Such a rotating head can be an intrinsic part of the tool,or it can be made by assembling the tool with a stationary noz-zle to work in combination with the downhole drilling motoror turbine, which would additionally rotate the tool, and noz-zle(s), around the tool axis. None of the existing tools or as-semblies had ever been used to cut circular notches in openhole wellbores, so a series of yard tests was performed withdifferent downhole tool configurations. The following high-lights the resulting key observations, using examples of a cou-ple of the tests performed with the high-pressure jetting CTtool (Tests N-1-T and N-1-B).

Cement targets were manufactured for the yard test to sim-ulate the open hole wellbore section. The block sample (ce-ment target) was placed into a larger steel tank, referred tohere as a “sample container,” with the objective to keep thesample and high-pressure jet contained in a safe area duringthe jetting test, Fig. 5.

In Test N-1-T, the jetting pressure was ramped up in stepsfrom 1,000 psi to 5,000 psi over the 125 minutes of the testtotal time, Fig. 6a. Although a shallow notch 0.5 cm deep wasalready observed after jetting at pressures around 1,000 psi,overall it took around 40 minutes to cut the notch to the depth


Fig. 5. Deployment of the yard test: The sample container general view (left);cement block sample (target) placed inside the sample container (right). Thejetting tool is rigidly fixed with the centralizer arms to prevent its oscillationaround the borehole axis, which otherwise may gain significant amplitude duringhigh-pressure jetting.Fig. 4. Effective hoop stress profiles along the wellbore axis in the notch vicinity.


of 2 cm at pressures of approximately 2,000 psi, which ap-peared too slow. Nevertheless, the notch was nice and smooth— free of cavities. A further increase of pressure to the rangefrom 3,600 psi to 3,700 psi and jetting for another 25 minutesmade the notch only 4 cm deep and from one side only — theother side remained at 2 cm. Subsequent jetting for 20 minutesat 4,000 psi deepened one side from 4 cm to 5 cm only. Thefollowing increase of pressure to 5,000 psi did not run assmoothly as required; the replacement of the pump was neededafter it was damaged by cavitation. After finally jetting at5,000 psi for about 40 minutes, the jet broke through theblock, Fig. 7a. The final depth of the notch increased signifi-cantly during this last 40-minute jetting stage — up to 14 cmat its deepest among the smooth regions of the notch. Theshallowest part of the notch — which was also the “slowest”one to grow, keeping slightly above 2 cm deep over the previ-ous jetting pressure levels — also jumped to 5 cm. On theborehole side, Test N-1-T also looked smooth and did not re-veal large breakouts, Fig. 7b; depth can be measured at all an-gles except the breakthrough side. The notch’s smooth depthof 14 cm is just a little bit smaller than 17 cm, which is the tar-geted depth of “one wellbore diameter.”

Then the question arose: Will there be any drastic changesin results — in notch depth and/or failure patterns — if the jet-ting was done at 5,000 psi pressure right from the start? Thatwas checked in Test N-1-B, Fig. 6b. The jet broke through theblock after 40 minutes of jetting, Fig. 7c, with a failure patternvery similar to the N-1-T case. A final notch depth of 15 cm —also very close to the N-1-T test result — was found, Fig. 7d.Therefore, this was a well repeated result, which showed theoverall consistency of the results.

Based on the test results presented here, the following con-clusions can be reached. A series of several jetting tests wasperformed in cement targets made of a 125 PCF cement recipe

using the actual CT tool, which comprised the rotating jettinghead equipped with 2 × jetting nozzle (0.156”). The test resultsdemonstrated mostly smooth failure patterns and consistentresults.

1. The ability to cut 10 cm to 15 cm deep circular notches with the 27⁄8” jetting tool was demonstrated repeatedly in the yard for the 17 cm diameter open hole in a cement target. This assumed pure water jetting and required around 40 minutes of jetting time.

2. A minimal jetting pressure of 1,000 psi was required to ini-tiate the erosion of notches. To cut the notch to the maxi-mum depth observed required at least 4,500 psi jetting pres-sure. There is evidence as well that jetting at intermediate pressures resulted in the notch depth’s being stabilized at shallower depths. This is intuitively correct; as the standoff distance increases, one expects jet dispersion and shear to decrease the jetting efficiency.

3. The depth of the notches in all cases is highly nonuniform — with respect to the angle — even in smooth regions, pos-sibly as a result of the nonlinear nature of the erosive inter-action with the fluid stream.

4. Jetting at constant pressure or ramping pressure up in steps was inconclusive as the two approaches did not lead to no-table differences in results — eventual notch depth — exceptramping required longer jetting times due to lower pressure stages. Although some results indicate smoother and more uniform notches as a result of ramping pumping schedules, this is not considered operationally relevant at this time, with the recommendation that pumping should take place at the maximum pressure immediately.

Overall, we consider the performed tests as successful:

• The maximum observed notch depth was 150 mm,which is 1 wellbore diameter for standard SaudiAramco open hole completions.


Fig. 6. The 125 pounds per cubic foot (PCF) cement target tests run with 0.156”nozzles. For each test, the jetting pressure and notch depth are plotted against thetime (in the graphs, left). The reported notch depth corresponds to its “deepest”part where the depth could be measured (given in cm values on the depthdiagrams, right). In sectors where the jet broke out of the cement target, the depthof notches cannot be detected, which is indicated with “x” in the depth diagrams.

Fig. 7. Post-test image of the target #1 block representing 125 PCF cement recipeused in the tests N-1-T and N-1-B (center). In both tests, the jet “broke out” ofthe block via a single face where the resulting hole appeared localized as well,leaving the remaining three faces intact (7a, 7c). Images of the borehole (7b, 7d)also demonstrate the smooth openings of both notches — free of large breakoutsand longitudinal cracks.


• We have strong evidence that this would increasefurther with additional available pumping pressure.

There were limitations to the experimental arrangement.First, the measured maximum penetration was a significantfraction of the block size and associated with breakouts nearthose regions. This means that to study reliably deeper jet penetration, the sample would need to be larger to eliminateboundary effects.

While the implementation of a similar test at high hydro-static pressure and elevated pressures would represent an ex-cessive engineering challenge, it is worth considering how thesetests might translate to a downhole environment and the re-sulting operational considerations. Taking into account highvelocities of water flow through the nozzle, there is an in-creased chance for the occurrence of cavitation in the jet — inthe areas of the flow with sudden pressure drop. It is knownthat the appearance of gas bubbles in the fluid jet due to cavi-tation can increase the efficiency of the water jet cutting by ad-ditional mechanisms that damage and erode materials9, andthat cavitation will be modulated by the hydrostatic pressureof the environment. This suggests that the efficiency of waterjetting drops with depth; it is believed that the most effectiveway to de-risk this for field operations is to employ abrasivesto ensure consistent and controlled erosive action independ-ently of entrained gas within the stream.

SEQUENCE DIVERTER

The diverter pill is an engineered slurry comprising a propri-etary blend of degradable particles with multimodal size distri-bution and fibers. The diverter composite pill was specificallydesigned to promote diversion in multistage fracture treat-ments for perforated cased hole wells where there is a limitedopen area and so limited control of the placement of the pill.

The composite fluid overcomes the limitations of traditionalchemical diverters by coupling degradable particles of a widesize distribution. Degradable fibers are added to improve dis-persion of the particles in the tubulars, thereby keeping thesolid slug highly concentrated. The fibers modify the rheologyof the composite fluid by imposing a yield stress, which hin-ders dispersion in the tubulars. Fibers also help to level the velocity profile toward the center of the conduit, which reducesshearing forces on the slugs and mitigates dispersion as well10.Large particles accumulate at the fracture entrance bridgingthe fracture face, and then the smaller particles reduce perme-ability and deliver temporary isolation. The fibers enhance par-ticle transport to ensure integrity of the blend from the surfaceto the near wellbore area, helping to mitigate pill dispersionand particle settling.

Particles and fibers completely degrade within three hourstriggered by the BHT; therefore no additional treatment is re-quired to put the well back in production, ensuring that all in-tervals are available to contribute.

COMPLETION DESIGN

Completion of this well required the setting of two balancedcement plugs in the open hole section. The lower plug wasrequired due to water-bearing porosity intervals below, while

the second plug was needed for support to land and cementthe 4½” liner. The liner was pressure tested to ensure therewould be no hydraulic leaks during the fracturing treatmentand then drilled out to expose the open hole section. Afterthat, the well was completed with 4½”, 13.5 lb/ft, C-95 tubingand liner with VAM-TOP high compression connectors and a4½” × 7”, VFLH 25 ft, polished bore receptacle and seal as-sembly. The completion was designed for a bottom-hole injec-tion pressure as high as 14,500 psi, which would not besufficient for a cased hole fracture design for this particularwell. Figure 8 is a schematic of the open hole completion.

FRACTURE DESIGN

Three targets were identified in the well, Fig. 9 (left), coveringa total area of 250 ft out of the 550 ft of open hole. The threetarget areas were selected based on porosity development anda clean gamma response. Due to the formation’s heterogeneity,permeability was a huge unknown, along with the uncertaintyas to the stress state and natural fractures that could be presentalong the open hole section.

Six notch locations were selected with the intention to lowerthe fracture initiation pressure and distribute the fractureacross the open hole interval. Cutting of the notches was per-formed with 35 bbl of 1 PPA sintered bauxite at 2 bpm. Eachstage was flushed with a gel fluid, and all six stages were per-formed consecutively. Tool integrity during the cutting stageswas determined by monitoring the CT injection pressure. Lossof pressure would indicate the jets had deteriorated and werenot providing sufficient cutting power.

Due to the large surface area, the treatment was designedfor three stages with two pill stages, Table 1. The design wasto pump a total of 300,000 lb of nonradioactive tracer prop-pant, with the stage volumes increasing with each stage. Thelarger volumes were placed toward the end, which was when


Fig. 8. Open hole completion schematic.


the proppant was placed into the tighter rock, providing maxi-mum penetration and fracture conductivity.

To determine the effectiveness of the notches and to obtaina better understanding of the breakdown pressures, a calibra-tion injection treatment of 300 bbl of cross-linked fluid wasfollowed by a temperature log. Breakdown pressures were lessthan originally calculated, allowing the fracture treatment tomove forward, and the temperature survey indicated goodfluid entry at the notches.

To avoid restimulating the same section, two diverter com-posite pills were deployed in two stages, with the goal to tem-porarily isolate each fracture. The volume of each pill, 900 lb,was engineered to cover 60 ft to 70 ft of fracture height, whichwas the expected fracture height growth based on fracture sim-ulations and previous experience in the area. As a reference,this volume is approximately eight to 10 times larger than thetypical pill volume used for cased holed perforated applica-tions; the large volume was directly related to the larger sur-face contacting the wellbore in the open hole case.

The deployment of the composite pill can be performed in acontinuous action right after the last proppant stage — 4 PPA

or 5 PPA — or as a separate stage after flushing. We opted forthe latter, which provides the flexibility to capture the post-fracture initial shut-in pressure (ISIP) for evaluation purposesand to have better control when the pill entered the formation;this job was the first case worldwide to deploy such pill volumes.

FRACTURE RESULTS

The entire open hole interval was fracture stimulated withthree proppant ramps separated by two diversion pills as perdesign — in the span of eight hours — improving operationalefficiency more than threefold. Diversion was confirmed by:(1) Pressure increases of 380 psi and 500 psi, respectively,when the pills landed on formation, Fig 10; and (2) Increasingthe trend of the ISIPs throughout the treatment, resulting in1,270 psi of net pressure gain, Fig. 11. Comparison was madeof the post-diagnostic injection test temperature log data withpost-fracture neutron log data, showing where the nonradioac-tive traceable proppant was placed, previously seen in Fig. 9,including into at least three notched pay intervals not brokendown during the injection test. Post-treatment production


Fig. 9. Post-diagnostic log indicating fracture diversion.


expectations were obtained and confirmed with a long-termwell test.

CONCLUSIONS

Analysis of the results allows the following conclusions to bedrawn:

1. The rotating notching tool was successfully deployed down


Stage Description Fluid Type Rate (bpm) Stage Vol (bbl) Proppant Vol (lb)

1 Pre-pad 45 PPTG 40 150

1 Pad 45 PPTG-XL 40 300

1 Slurry 0.5 to 4 PPA 45 PPTG-XL 40 463 40,000

1 Displacement 20 PPTG 40 171

Shutdown

Pill 1 Spacer 40 PPTG 7 10

Pill 1 Pill Pill 7 20


Pill 1 Displacement 20 PPTG 10 131

Pill 1 Placement 20 PPTG 10 40

Pill 1 SDT 20 PPTG 45 100

Shutdown


2 Pad 45 PPTG-XL 45 350

2 Slurry 1 to 5 PPA 45 PPTG-XL 45 860 100,000


Shutdown


Pill 2 Pill Pill 7 20


Pill 2 Displacement 20 PPTG 7 124

Pill 2 Placement 20 PPTG 10 40

Pill 2 SDT 20 PPTG 10 100

Shutdown


3 Pad 45 PPTG-XL 45 500 160,000

3 Slurry 1 to 6 PPA 45 PPTG-XL 45 1,313


Total Proppant 300,000

T Table 1. Treatment design

Fig. 10. Pressure treatment plot indicating pressure effects from the pill stages.

Fig. 11. Increasing ISIP evolution indicating new rock breaking down.


hole via CT providing a 360° circular notch, supported by the series of yard tests with cement targets, which tested theactual field configuration of the tool.

2. Open hole notches reduce breakdown pressures by increasingthe tensile stress at the wellbore in the notch vicinity. This promotes the initiation of longitudinal fractures in that zone.

3. Open hole notches can be used to provide for fracture initi-ation at multiple spots along the open hole section, as was indicated by the nonradioactive traceable proppant placed into at least three notched pay intervals not broken down during the injection test.

4. A combination of degradable particulates and fibers will divert fluids in an open hole, as was indicated by an increasing ISIP between stages and the nonradioactive tracer diagnostic log.

5. Pill volumes approximately eight to 10 times larger than those of a cased hole application were employed to ensure diversion in the open hole.

Overall, the feasibility of a new two-step sequenced fractur-ing technique was demonstrated for open hole wellbores. Thetechnique uses notching of the target pay zones to ensure theselected areas are preferentially fractured with subsequentpumping stages. Notching is followed by the injection phase,without any mechanical isolation; the entire 552 ft length ofopen hole was exposed to elevated pressures. Clearly, theweakest point initiated the first fracture. Injection stages wereinterchanged with diversion phases to temporarily impedefluid flow into growing fractures and allow the pressure to re-build to fracture the next weakest zone, effectively generatingmultiple fractures at targeted zones without mechanical isola-tion. This makes the implemented two-step fracturing tech-nique, i.e., notching plus diversion, a practical, efficient andcost-effective preferred solution for completing and fracturingsimilar zones that are traditionally bypassed, resulting in acost-effective means to increase production and reserves.

ACKNOWLEDGMENTS

The authors wish to thank the management of Saudi Aramcoand Schlumberger for their support and permission to publishthis article. The authors would also like to thank the SaudiAramco Unconventional Fracturing Team for supporting andsuccessfully executing the fracture treatment. The support ofSchlumberger’s Well Intervention, Well Services and CementingTeams in ‘Udhailiyah and al-Khobar is also very much appreciated.

This article was presented at the SPE Hydraulic FracturingTechnology Conference, The Woodlands, Texas, February 9-11, 2016.

REFERENCES

1. Chang, F.F., Bartko, K., Dyer, S., Aidagulov, G., Suarez-Rivera, R. and Lund, J.: “Multiple Fracture Initiation inOpen Hole without Mechanical Isolation: The First Step toFulfill an Ambition,” SPE paper 168638, presented at theSPE Hydraulic Fracture Technology Conference, TheWoodlands, Texas, February 4-6, 2014.

2. Aidagulov, G., Alekseenko, O., Chang, F.F., Bartko, K.,Cherny, S., Esipov, D., et al.: “Model of Hydraulic FractureInitiation Pressure from the Notched Open Hole,” SPEpaper 178027, presented at the SPE Saudi Arabia SectionAnnual Technical Symposium and Exhibition, al-Khobar,Saudi Arabia, April 21-23, 2015.

3. Adil, F., Pande, K. and Raina, B.: “First Open HoleHydraulic Fracturing Treatment Using Diverter Technologyin India,” SPE paper 167690, presented at the SPE/EAGEEuropean Unconventional Conference and Exhibition,Vienna, Austria, February 25-27, 2014.

4. Jaeger, J.C., Cook, N.G.W. and Zimmerman, R.W.:Fundamentals of Rock Mechanics, 4th edition, Wiley-Blackwell Publishing, Hoboken, New Jersey, 2007, 488 p.

5. Detournay, E. and Carbonell, R.: “Fracture MechanicsAnalysis of the Breakdown Process in Mini-fracture orLeak Off Test,” SPE Production & Facilities, Vol. 12, No.3, August 1997, pp. 195-199.

6. Becker, A.A.: The Boundary Element Method inEngineering: A Complete Course, 1st edition, McGraw-Hill, New York, 1992, 350 p.

7. Pittman, F.C., Harriman, D.W. and St. John, J.C.:“Investigation of Abrasive-Laden-Fluid Method forPerforation and Fracture Initiation,” Journal of PetroleumTechnology, Vol. 13, No. 5, May 1961, pp. 489-495.

8. Zwanenburg, M., Schoenmakers, J. and Mulder, G.: “WellAbandonment: Abrasive Jetting to Access a PoorlyCemented Annulus and Placing a Sealant,” SPE paper159216, presented at the SPE Annual Technical Conferenceand Exhibition, San Antonio, Texas, October 8-10, 2012.

9. Momber, A.W.: “Wear of Rocks by Water Flow,”International Journal of Rock Mechanics and MiningSciences, Vol. 41, No. 1, January 2004, pp. 51-68.

10. Kraemer, C., Lecerf, B., Torres, J., Gomez, H., Usoltsev, D., Rutledge, J., et al.: “A Novel Completion Method for Sequenced Fracturing in the Eagle Ford Shale,” SPE paper169010, presented at the SPE Unconventional Resources Conference, The Woodlands, Texas, April 1-3, 2014.




BIOGRAPHIES

Kirk M. Bartko is a Senior PetroleumEngineering Consultant with SaudiAramco’s Unconventional GasOperations Department with theTechnical Support Unit focusing ontrial testing new technologies forcompletions and stimulation. He

joined Saudi Aramco in 2000, where he works to supporthydraulic fracturing and completion technologies across allSaudi Arabia operations. Kirk’s experience includes 19years with ARCO with various global assignments inlocations, including Texas, Alaska, Algeria, and theResearch Technology Center supporting U.S. andinternational operations.

He has authored and coauthored more than 40technical papers on well stimulation and is a recipient offour U.S. granted patents, and has been actively involved inthe Society of Petroleum Engineers (SPE) since 1977.

Kirk received his B.S. degree in Petroleum Engineeringfrom the University of Wyoming, Laramie, WY.

Roberto Tineo is currently a SeniorProduction Stimulation Engineer forSchlumberger working at theUnconventional Resources Center inDhahran, Saudi Arabia. He has beenwith Schlumberger for 15 years.Roberto started his career as a

Stimulation Field Engineer in Eastern Venezuela, workingon design, execution and evaluation of fracturing, sandcontrol and matrix acidizing treatments. From EasternVenezuela he moved to the West as a Technical SalesEngineer to support stimulation operations in LakeMaracaibo. Roberto then worked for 4 years in California,U.S., as a Design and Evaluation Services Client Engineer,involved on horizontal fracture stimulation designs,conventional formations and the Monterey shale. Hiscurrent assignment in Saudi Arabia is to advise, design andevaluate fracture treatments for Saudi Aramco’sunconventional shale gas resources.

Roberto received his B.S. degree in ElectronicEngineering from Simón Bolivar University, Caracas,Venezuela.

joined Saudi Aramco

Stimulation Field Engineer

Dr. Gallyam Aidagulov started hisSchlumberger career in 2004 when hejoined the company research center inMoscow, Russia. Since that time,Gallyam has focused on geomechanicsthrough his involvement in variousprojects where he applied and further

developed his expertise in computational mechanics fordevelopment of theoretical and numerical models of suchprocesses as proppant flow back, sanding, faultreactivation and reservoir rock failure localization.

In March 2012, he moved to the SchlumbergerCarbonate Research Center in Dhahran, Saudi Arabia, towork on numerical and laboratory studies of hydraulicfracturing under a joint research project with SaudiAramco.

In 2000 and 2004, Gallyam received his M.S. and Ph.D.degrees, respectively, in Computational Mathematics fromthe Lomonosov Moscow State University, Moscow, Russia.

Ziad Al-Jalal is currently working asthe Stimulation Domain Manager forSchlumberger, where he is involved infracturing projects in Saudi Arabia andBahrain. He has 15 years of experiencein fracturing treatments in bothconventional and unconventional

wells. Ziad joined Schlumberger in 2000 as a FracturingField Engineer in Western Siberia, Russia, for four years,then as a Technical Engineer in Saudi Arabia. From 2008to 2012, he was a Team Leader in the Tight Gas Center ofExcellence based in Dhahran, Saudi Arabia. Ziadpreviously worked as a Senior Production and StimulationEngineer in Oklahoma City, OK, from 2012 to 2014.

He received his B.S. degree in Mechanical Engineeringfrom King Fahd University of Petroleum and Minerals(KFUPM), Dhahran, Saudi Arabia, in 1999.

Andrew Boucher has over 15 years ofwell production and completionengineering experience, with a focuson fracturing and stimulation. He hasheld various technical, sales andoperational positions withSchlumberger, primarily in North and

South America. Most recently, Andrew held the position ofTechnical Manager for Fracturing and Stimulation for theArabian GeoMarket.

In 1999, he received his B.S. degree in ChemicalEngineering from Queen’s University, Kingston, Ontario,Canada.

developed his expertise

wells. Ziad joined Schlumberger

South America. Most


ABSTRACTprovide favorable flow properties. They are commercialized invarious ratings, based on the strength and density of thespheres. The strengths of HGSs range from 2,000 psi to18,000 psi, with true densities between 0.29 gm/cc and 0.63gm/cc, and their particle sizes range between 1 µm and 100µm. With the use of HGSs, the density of a water-based fluidcan be reduced to 41 pounds per cubic foot (PCF). Drilling flu-ids can be formulated with an upper limit of 40 vol% HGSwhile maintaining suitable rheology and mud characteristics1.The rheological properties of HGS-based fluids are similar tothose of conventional fluids and can be calculated throughEinstein’s viscosity model2.

Drilling fluids formulated with HGSs permit measurementswhile drilling and have been found to be compatible with con-ventional surface equipment3. HGSs allow the employment ofnear balanced and underbalanced drilling, which reduces thedifferential pressure in the wellbore. Drilling in low differentialpressure conditions can result in numerous benefits, such as anincrease in the rate of penetration (ROP), reduction in forma-tion damage, and elimination of loss of circulation and differ-ential pipe sticking4. These improvements ultimately lead tolower nonproductive time and greater efficiencies.

To reduce hydrostatic pressure on the formation, a low-den-sity cement (LDC) needs to be applied, especially on a frac-tured weak formation. To reduce the density of cement, watercan be added in large volumes, but this will affect the mechani-cal properties of the cement, such as its compressive strengthand permeability. This type of cement is called water extendercement. The lowest density that can be formulated using waterextender cements is 86 PCF5. Water extender cements also re-quire multistage operations to avoid fracturing the formationdue to high hydrostatic pressure, and multistage cementing canfail, which then requires remedial operations, such as perfora-tion and squeeze jobs6-8.

Nitrogen can be used to make LDC, but attention is re-quired to achieve the required density. Another way to makeLDC is to use materials with low SGs, such as hollow micros-pheres (ceramic or glass), mixed with the cement9-11. Gas con-tained in these hollow glass materials enable the reduction ofcement density down to approximately 60 PCF12. There areseveral ways to make LDC other than just mixing hollow mi-crospheres with cement; i.e., mixing coarse and fine cement

Hollow glass spheres (HGSs) provide an attractive method toreduce the densities of drilling fluids and cement slurries fordifferent objectives. There are several pressure ratings forHGSs, and selecting and testing the right type for the suitableapplication is important.

The objective of this article is to evaluate the performanceand stability of HGSs in three formulations: (a) HGS-basedfluids at different pH conditions, (b) low-density water-baseddrilling fluids with HGSs as a density reducing additive, and(c) low-density cement (LDC) with HGSs as a density reducingadditive.

The evaluation of the stability of low density inhibited wa-ter-based fluids formulated with HGSs in diverse pH environ-ments was for their potential application in the Wasiaformations in Saudi Arabia. Intensive testing of the fluids in-cluded rheological properties, pH and density measurementsbefore hot rolling (BHR) and after hot rolling (AHR) in diff-erent pH environments at high-pressure/high temperature(HPHT) for extended periods of time — up to four days.

The evaluation of the stability of LDC utilizing HGSs wasfor their potential to cement shallow casings in gas wells andoil wells in Saudi Arabia. In this study, we present the resultsof extensive lab work that included rheology measurements,thickening time tests, free water and sedimentation tests, afluid loss test and a compressive strength test.

Data generated supported the use of low-density fluids for-mulated with HGSs in the Wasia formation when applicable.Also, this study supported the use of the examined cement forcasings under shallow conditions in gas wells and oil wells.The shallow conditions simulated in the lab tests were at astatic temperature of 158 ºF and at 2,500 psi.

INTRODUCTION

Hollow glass spheres (HGSs) are lightweight solids composedof soda-lime-borosilicate glass. They are incompressible mi-crospheres with specific gravities (SGs) lower than that of wa-ter. The high strength and low density of HGSs make them anattractive method to reduce the density of drilling fluids andcement slurries. Furthermore, HGSs are chemically inert and

Investigation of the Stability of HollowGlass Spheres in Fluids and Cement Slurriesfor Potential Field Applications in SaudiArabiaAuthors: Dr. Abdullah S. Al-Yami, Mohammed B. Al-Awami and Dr. Vikrant B. Wagle



particles, fly ash, fumed silica, hollow microspheres and wa-ter13. Another way is to mix hollow microspheres with plasti-cizer, cement and aluminum metal powder and sodiumsulfate14. The first application of LDC utilizing hollow micros-pheres took place in 1980 at a density of approximately 69PCF15.

The objectives of this article are:

• To formulate and evaluate HGSs for drilling fluidsapplications.

• To formulate and evaluate HGSs for cementingoperations.

OVERVIEW OF SUCCESSFUL FIELD IMPLEMENTATIONSOF HGS-BASED DRILLING FLUIDS

Drilling fluids formulated with HGSs have been tested in nu-merous field trials in the past decade, and many of thesedrilling fluids have been proven successful. HGS-based fluid ismostly deployed in areas with major problems, such as areaswith extremely slow ROP, frequent differential pipe sticking,severe or total loss of circulation and high formation damagein reservoir sections. HGS-based fluid successfully eliminateddifferential sticking in the field deployment3 and was able toreduce mud losses from 100+ bbl/hr to 6 bbl/hr in India16. Inareas of slow ROP, oil-based mud formulated with HGSs suc-cessfully reduced drilling operations by 11 days in Venezuela17.A study conducted by Chen and Burnett (2003)18 determinedthat HGSs do not create additional damage to the formation’spermeability. The small particle size of HGSs, though, leads tothe formation of a tighter filter cake19. In these examples ofHGS field deployment, added benefits such as reduced torqueand enhanced productivity have also been observed.

OVERVIEW OF SUCCESSFUL FIELD IMPLEMENTATIONSOF HGS-BASED LDCs

LDCs have been used throughout the industry for many yearsas a specialty cement for application in areas of weak forma-tions. Ripley et al. (1981)20 have described the use of small di-ameter, inorganic, high strength microspheres in LDC slurrieswith improved compressive strength, enabling the slurry tomaintain its low density even at high pressures. Wu and Onan(1986)21 have described the use of high strength microspheresin LDC as resulting in improved primary casing and liner ce-menting in the Gulf of Bohai. Al-Yami et al. (2007, 2008)22, 23

have conducted a long-term evaluation of LDC stability whereLDC is used to achieve zonal isolation across weak sandstoneand carbonate formations in the fields of Saudi Arabia. Fieldtreatments were conducted without encountering any opera-tional problems, and the cement maintained isolation for morethan three years, which confirmed the effectiveness of the LDCsystem. Al-Yami et al. (2012)24 have also tested low-density


systems at 300 °F. After testing the durability of LDC at highertemperatures and in different operational scenarios, they haveshown that the LDC is durable even in high-pressure/high tem-perature (HPHT) conditions. Carver et al. (2011)25 have usedhollow microsphere-based LDCs for increasing primary ce-menting success in steam injected, low fracture gradient areas.Wang and Wang (2013)26 have used an ultra-LDC system withHGSs as a weight reducing additive to control lost circulationin coalbed methane wells.

METHODS AND MATERIALS

The performance and stability of HGSs were assessed in threeformulations: (a) HGS-based fluids in different pH conditions,(b) low-density water-based drilling fluids with HGSs as a den-sity reducing additive, and (c) LDC with HGSs as a density reducing additive.

The experimental procedure to evaluate the stability andperformance of HGSs is given as follows.

Formulating HGS-based Fluids in Different pH Conditions

In this study, 57.5 PCF (7.69 lb/gal) water-based fluids weredesigned having different pH values — acid condition pH < 4,original pH = 9 and basic condition pH > 11 — to assess theeffect of pH on the stability of the HGSs. All fluids were de-signed utilizing HGS-8000 (SG = 0.42) to get a density of ap-proximately 57.5 PCF, Table 1. The additives were mixed withwater using a standard multi-mixer. Mixing operations wereobserved to ensure proper mixing of each component.

Evaluation of Hollow Glass Microspheres in Low-Density

Drilling Fluids

In this study, 57.5 PCF water-based drilling fluids were de-signed with HGS-8000. The HGS-based drilling fluids wereformulated with a viscosifier, fluid loss additive, shale in-hibitors, etc. The fluids were hot rolled at 160 °F/250 °F for16 hours in HPHT aging cells.

Additives

Concentration (ppb)

Original pH (pH = 9)

Basic Conditions (pH > 11)

Acidic Conditions

(pH < 4)

Water 306.8 306.3 302.9

HGS 18.01 18.06 18.40

XC-Polymer 0.5 0.5 0.5

NaOH – 0.15 –

HCl Acid – – 3.54

T

Table 1. Formulation of the fluids at different pH conditions


Fluid Loss Test. Dynamic fluid loss, i.e., loss of fluid from theslurry while it is being placed, results in an increase in slurrydensity, which may cause loss of circulation. Other properties,such as rheology and thickening time, also may be adverselyaffected. Static fluid loss, i.e., loss of fluid from the slurry afterplacement, if not carefully controlled, will lead to a slurry vol-ume reduction and pressure drop that can allow formation fluids to enter the slurry28.

Curing at Downhole Conditions. A HPHT curing chamberwas used for curing the cement specimens at the required con-ditions. Cubical molds, 2” × 2” × 2”, and cylindrical cells,1.4” diameter and 12” length, were lowered into the curingchamber27. Pressures and temperatures were maintained untilshortly before the end of the curing, when they were reducedto ambient conditions.

Compressive Strength Test. The cubical molds, 2” × 2” × 2”,were removed from the molds to be placed in a hydraulic presswhere force was exerted on each cube until failure, which is incompliance with API specifications for the oil well’s cementtesting27. The compressive strength was measured after curingthe samples for four days.

Density Measurements of HGSs. The density of the hollowglass microspheres was determined using the following speci-fied procedure:

1. Weigh the empty flask to the nearest 0.01 g. 2. Add approximately one-third of the volume of glass bub-

bles to the flask, and weigh the flask and the powder to the nearest 0.01 g.

3. Add sufficient mineral oil to cover and wet the glass bubbles.Stopper the flask and agitate it for several minutes, ensuringthat neither air pockets nor lumps of glass bubbles exist. Wash the stopper and the walls of the flask with mineral oiluntil they are free of glass bubbles and the flask is filled to the 100 mL level.

4. Weigh the flask and the glass bubbles and mineral oil to the nearest 0.01 g.

5. Empty the flask. Clean and dry the flask, add 100 mL of mineral oil, and weigh the flask and the mineral oil to the nearest 0.01 g.

6. Calculate the density of the mineral oil, Ps, using the formulain Eqn. 2:

PS = 10(MFS – MF) (2)

where: PS = density of mineral oil (g/L) MFS = mass of flask plus mineral oil (g) MF = mass of flask (g)

7. Calculate the density of the glass bubbles using the formula

Evaluation of Hollow Glass Microspheres in LDC Slurry

A 75 PCF LDC slurry was formulated using HGS-4000 (SG =0.38) hollow glass microspheres. This slurry was then evalu-ated for its performance after curing it at 158 °F and 2,500 psifor four days.

Slurry Preparation Procedure. The LDC was formulated in thelab using a standard American Petroleum Institute (API)blender. The maximum speed during slurry preparation was4,000 revolutions per minute (rpm) instead of the typical12,000 rpm. To apply the same mixing energy, the duration ofmixing was changed to 330 seconds at 4,000 rpm, instead of15 seconds at 4,000 rpm and 35 seconds at 12,000 rpm22. Theequation of mixing energy is27:

(1)

where:E = mixing energy (kJ)M = mass of slurry (kg)k = 6.1 × 10-8 m5/s (constant found experimentally)�= rotational speed (radians/s)t = mixing time(s)V = slurry volume (m3)

After mixing and preparing the slurry, it was placed in aconsistometer, and a pressure of 2,500 psi was applied. Theobjective of placing the cement under pressure is to simulatefield placement under a 2,500 psi hydrostatic column, basedon the usual placement of 75 PCF LDC. All tests were con-ducted after applying 2,500 psi (simulating hydrostatic pres-sure on the LDC) to find out if crushing the hollow microsphereshad an effect on the physical properties tested.

Slurry Rheology. The slurry was conditioned in the atmos-pheric consistometer before measuring rheological readings. Astandard rheometer was used to measure the slurry rheology27.

Thickening Time Test. A standard API HPHT consistometerwas used to evaluate the pumpability of the cement slurry.

Free Water and Slurry Sedimentation Tests. Water separationin slurries is an indication of bad performance and a potentialzonal isolation problem. So, a free water test was conductedusing 250 ml in a graduated cylinder for two hours accordingto API procedures. Settling is another indication of improperperformance and likely zonal isolation problems. This can betested for by measuring the densities of different sections of acured cement column27. A gas pycnometer was used to meas-ure the density of these different sections at the specified con-ditions previously mentioned. Points 2” from the top, middleand bottom sections of a 12” long and 1.4” diameter sampleof the cement were measured for densities.



in Eqn. 3:

(3)

where: PP = density of glass bubbles (g/L) MFP = mass of flask plus glass bubbles (g) MF = mass of flask (g) MFPS = mass of flask plus glass bubbles and mineral oil (g) PS = density of mineral oil (g/L)

Particle Size Distribution

The particle size distribution of the hollow glass microsphereswas determined using a Malvern Mastersizer 2000.

RESULTS AND DISCUSSION

Effect of pH on Hollow Glass Microspheres

The stability of the spheres in drilling fluids is critical to sus-taining a practical and effective drilling fluid. Unplannedbreakage or dissolution of the spheres in the wellbore whiledrilling could lead to numerous problems, such as increasedformation damage and loss of circulation due to the sudden increase in the density of the drilling fluid. Alawami et al.(2015)29 has studied the effect of various pH conditions on thestability of HGSs. In that study, HGS-based fluids after hotrolling (AHR) at a pressure of 500 psi and a temperature of250 °F for intervals up to four days showed slight changes indensity. The results showed a slight density increase up to 0.5PCF AHR in the fluids at 250 °F in alkaline conditions. Thiscould be attributed to a dissolution of the spheres driven bythe reaction of sodium hydroxide (NaOH) with the silicon-oxygen bond in borosilicate HGS glass. The addition ofNaOH boosts the forward reaction of water with the silicon-oxygen bond, Eqn. 4, which consequently encourages furtherdissolution of the spheres, Eqn. 530.

Si-O-Si + H2O = SiOH HOSi (4)

Si-O-Si + NaOH = SiOH Na+OSi (5)

In acidic conditions, pH < 4, on the other hand, the spheresrevealed extremely high stability. The density of the fluid wassustained without any changes at all hot rolling durations.Table 2 is a summary of the stability results of the HGS in thedifferent pH conditions.

Evaluation of Hollow Glass Microspheres in Low-Density

Drilling Fluids

Alawami et al. (2015)29 have assessed two 57.5 PCF formulationsof inhibited water-based muds using HGSs as density reducing

agents, Tables 3 and 4. The two formulations targeted a den-sity of a pH between 9 and 10.

The tests displayed excellent results with stable density andpH before and after three days of hot rolling, Table 5. Formu-lation #1 was hot rolled at a temperature of 250 °F, while For-mulation #2 was hot rolled at a temperature of 160 °F; thesesimulated real wellbore conditions in the Wasia formation. Thedensity of the fluid remained within 0.1 PCF, and the pH val-ues were sustained within the desired range of 9 to 10. Theplastic viscosity and gel strength values were kept low for bothformulations. The yield point of Formulation #2 recordedhigher values than that of Formulation #1; however, both valuesare within the practical range.


Hot Rolling Duration(Days)

Density Increase (lbm/ft3)

Original pH (pH ~9)

High pH (pH > 11)

Low pH(pH < 4)

1 day – 0.0 –

2 days 0.5 0.2 0.0

3 days 0.2 – 0.0

4 days 0.3 0.5 0.0

T

Table 2. Summary of the stability results of HGSs having different pH values28

Additives Concentration (ppb)

Water 280.5

Bentonite 2

Soda Ash 0.3

Shale Inhibitor 10

XC-Polymer 0.5

Bio-polymer 2

Filtration Control 0.75

HT Filtration Control 4

HGSs 24.6

T

Table 3. Formulation #1 of a typical fluid, hot rolled at 250 °F

Additives Concentration (ppb)

Water 296.3

Bentonite 3

XC-Polymer 0.5

Shale Inhibitor 1

Bio-polymer 4

HGSs 20.3

NaOH As needed

T Table 4. Formulation #2 of a typical fluid, hot rolled at 160 °F


Evaluation of Hollow Glass Microspheres in LDC Slurry

The density of hollow glass microspheres was measured usingthe procedure previously described. The density of the HGSscalculated from Eqn. 5 was 377 g/L (0.377 g/ml).

The particle size distribution of the HGS-4000 hollow glassmicrospheres is given in Table 6. The HGSs show a particlesize distribution with a d(0.5) value of 41.385.

Cement crushing tests were done at a pressure of 2,500 psiand 4,000 psi. These two pressures were selected to simulatefield conditions; they represent the hydrostatic pressure ap-plied on the column of the cement slurry.

In the crushing test, the slurry density was measured beforeand after exposing the cement slurry to 2,500 psi and 4,000psi, using a mud balance. The density measurement was 76PCF after exposure to 2,500 psi and 77 PCF after exposure to4,000 psi.

Therefore, the following two conclusions can be drawnfrom the crushing tests:

• The LDC slurry that is pressurized at a conditioningpressure of 2,500 psi should result in approximately a 1 PCF to 2 PCF increase in density, compared to theinitial density.

• The LDC slurry that is pressurized at a conditioningpressure of 4,000 psi should result in approximately a 2 PCF to 3 PCF increase in density, compared to theinitial density.

The pumping time was found to be 6 hr 49 min (409 min at100 Bc) for shallow conditions, Fig. 1. The static fluid lossvalue for the LDC slurry was 344.4 cc.

Test data showing zero free water and no significant settlingor sedimentation are indications of good slurry stability andgood potential for zonal isolation27. The free water test in thestudy showed no settling in the LDC slurry. The LDC cylinderwas cured at 2,500 psi and 158 °F for four days. Sections ofthis cylinder then were cut and their density was measured.Table 7 shows that the density of the six sections of the LDCcylinder did not vary from one section to another. These re-sults confirmed that there was no settling of the LDC over 24hours.

The growth of hydrated calcium silicate crystalline struc-tures in cement leads to the development of greater compres-sive strength. More strength can grow due to structure growthwith each other31.

One study indicates that a 100 psi compressive strength isenough for casing support32. A compressive strength of 500 psiis needed for casing support, according to another study28. Thefinal compressive strength of the LDC in this study after curingat 158 °F and 2,500 psi for four days was 2,487 psi, Fig. 2.


Measurement Formulation #1

Formulation #2

BHR AHR BHR AHR

Density (PCF) 57.5 57.4 57.5 57.4

pH 9.75 9 9.66 9.76

10 s Gel Strength (lb/100 ft2) 13 2.7 – 5.3

10 m Gel Strength (lb/100 ft2) 18.5 3.3 – 11.3

Plastic Viscosity (cP) 21.9 11.3 – 11.8

Yield Point (lb/100 ft2) 63.2 10.3 – 20.8

T

Table 5. Performance of HGSs in drilling fluids before and after hot rolling at 160°F (Formulation #1) and 250 °F (Formulation #2)28

d(0.1) d(0.5) d(0.9)

HGS-4000 17.138 41.385 81.591

T

Table 6. Particle size distribution of HGS-4000 hollow glass microspheres

Fig. 1. Thickening time chart of the LDC at 158 °F and 2,500 psi.

Sections Wt. in Water

Bottom 85.9 PCF

1 86.1 PCF

2 85.9 PCF

3 85.4 PCF

4 85.2 PCF

Top 85.6 PCF

T Table 7. Density measurements of different sections in the LDC test cylinder


CONCLUSIONS

1. At pH = 9, the HGSs were found to be stable at high tem-peratures. The HGS-based fluids experienced a slight increase in density, with a maximum change of 0.5 PCF.

2. At high temperatures and higher pH values (pH > 11), the HGS-based fluids experienced a drop in pH values, accom-panied by a slight increase in density.

3. The inhibited water-based drilling fluids formulated with HGSs yielded favorable rheology and stable mud character-istics.

4. HGS-based LDC, after curing at 158 °F and 2,500 psi for four days, gave a good compressive strength of 2,487 psi.

5. In the crushing test, exposure of the cement slurry to 2,500 psi and 4,000 psi resulted in a 76 PCF slurry after exposure to 2,500 psi and a 77 PCF slurry after exposure to 4,000 psi.

ACKNOWLEDGMENTS

The authors would like to thank the management of SaudiAramco for their support and permission to publish this article.

This article was presented at the SPE Kuwait Oil & GasShow and Conference, Mishref, Kuwait, October 11-14, 2015.

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3. Arco, M.J., Blanco, J.G., Marquez, R.L., Garavito, S.M.,Tovar, J.G., Farias, A.F., et al.: “Field Application of GlassBubbles as Density Reducing Agent,” SPE paper 62899,presented at the SPE Annual Technical Conference andExhibition, Dallas, Texas, October 1-4, 2000.

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8. Kulkarni, S.V. and Hina, D.S.: “A Novel LightweightCement Slurry and Placement Technique for CoveringWeak Shale in Appalachian Basin,” SPE paper 57449,presented at the SPE Eastern Regional Conference andExhibition, Charleston, West Virginia, October 21-22, 1999.

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12. Root, R.L., Barrett, N.D. and Spangle, L.B.: “Foamed Cement: A New Technique to Solve Old Problems,” SPE paper 10879, presented at the SPE Rocky Mountain Regional Meeting, Billings, Montana, May 19-21, 1982.

13. Dao, B., Ravi, K.M., Vijn, J.P., Noik, C. and Rivereau, A.: “Lightweight Well Cement Compositions and Methods,” U.S. Patent No. 6,562,122, 2003.

14. Dillenbeck, R.L., Heinold, T., Rogers, M.J. and Bray, W.S.: “Ultra-Low Density Cementitious Slurries for Use inCementing of Oil and Gas Wells,” U.S. Patent No. 6,832,652, 2004.


Fig. 2. An example of the LDC API compressive strength load chart after curingthe LDC at 158 °F and 2,500 psi.


15. Smith, R.C., Powers, C.A. and Dobkins, T.A.: “A New Ultra-Lightweight Cement with Super Strength,” Journal of Petroleum Technology, Vol. 32, No. 8, August 1980, pp. 1438-1444.

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17. Blanco, J., Ramirez, F., Mata, F., Ojeda, A. and Atencio, B.: “Field Application of Glass Bubbles as a Density Reducing Agent in an Oil-based Drilling Fluid for Marginal/Low Permeability/Low-Pressure Reservoirs,” SPE paper 75508, presented at the SPE Gas Technology Symposium, Calgary, Alberta, Canada, April 30-May 2, 2002.

18. Chen, G. and Burnett, D.: “Improving Performance of Low Density Drilling Fluids with Hollow Glass Spheres,” SPE paper 82276, presented at the SPE European Formation Damage Conference, The Hague, The Netherlands, May 13-14, 2003.

19. Halkyard, J., Anderson, M.R. and Maurer, W.C.: “Hollow Glass Microspheres: An Option for Dual Gradient Drilling and Deep Ocean Mining Lift,” OTC paper 25044, presented at the Offshore Technology Conference-Asia, Kuala Lumpur, Malaysia, March 25-28,2014.

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BIOGRAPHIES

Dr. Abdullah S. Al-Yami is aPetroleum Engineer with the DrillingTechnology Team of Saudi Aramco’sExploration and PetroleumEngineering Center – AdvancedResearch Center (EXPEC ARC).

In 2014, he received the RegionalDrilling Engineering Award from the Society of PetroleumEngineers (SPE). Abdullah is a coauthor of the textbookUnderbalanced Drilling: Limits and Extremes. He hasfour granted U.S. patents and more than 16 filed patents,all in the area of drilling and completions. Abdullah hasmore than 40 publications to his credit and is a technicaleditor for the SPE Drilling and Completion journal.

He received his B.S. degree in Chemistry from theFlorida Institute of Technology, Melbourne, FL; his M.S.degree in Petroleum Engineering from King Fahd Universityof Petroleum and Minerals (KFUPM), Dhahran, SaudiArabia; and his Ph.D. degree in Petroleum Engineeringfrom Texas A&M University, College Station, TX.

Mohammed B. Al-Awami is aPetroleum Engineer with the DrillingTechnology Division of SaudiAramco’s Exploration and PetroleumEngineering Center – AdvancedResearch Center (EXPEC ARC). Hejoined Saudi Aramco in 2014 and has

published two Society of Petroleum Engineers (SPE)technical papers alongside one patent application in thefirst year of his professional career. Mohammed’s researchefforts have focused on drilling fluids, lost circulationmaterials and cement slurries. He has also explored thedevelopment potential of several local resources, such asbentonite and volcanic ash in Saudi Arabia. Mohammedhas seen his interest grow in managed pressure drilling anddrilling automation while pursuing the latest innovations indrilling engineering.

He is currently working with the Exploration and OilDrilling Engineering Department to gain a firsthandunderstanding of the challenges and adversities faced there.Mohammed is engaged in the design and planning ofproduction, evaluation and injection wells in major SaudiArabian oil fields, such as Abu Hadriya and Berri.

In 2014, he received his B.S. degree in PetroleumEngineering from the University of Oklahoma, Norman, OK.

Drilling Engineering

published two Society

Dr. Vikrant B. Wagle is a PetroleumScientist with the Drilling TechnologyTeam of Saudi Aramco’s Explorationand Petroleum Engineering Center –Advanced Research Center (EXPECARC). His experience revolves aroundthe design of novel, environmentally

friendly drilling fluid additives and the development ofhigh-pressure/high temperature tolerant drilling fluidsystems.

Vikrant has 18 technical publications and four grantedU.S. patents, and he has filed 21 U.S. patent applications,all in the area of drilling and completions.

He received his M.S. degree in Chemistry from theUniversity of Mumbai, Mumbai, India, and his Ph.D.degree in Surfactant and Colloidal Science from theMumbai University Institute of Chemical Technology,Mumbai, India.

friendly drilling fluid


ABSTRACTINTRODUCTION

A reservoir’s lateral and vertical heterogeneity and complexityposes challenges in exploiting carbonate reservoirs1-3. Typicalcarbonate formations can exhibit low reservoir quality, requir-ing long laterals and appropriate stimulation methods to makethem commercially viable4. The high temperature also requiresstable acid properties for deep penetration and optimal etchingof the formation3. Anhydrate streaks and high in situ stresscan restrict fracture growth. Moreover, condensate dropoutand banking can have severe consequences on gas productionand recovery.

Acid stimulation has become the preferred technology toimprove gas production and reservoir sustainability. To addressmany varied challenges, different technologies have been appliedover the years, from simple acid washes to major acid fracturingoperations that use various fluids and acid systems, divertermechanisms, novel completions and improved chemicals3.

Numerous well, reservoir and operational data were ana-lyzed to understand their impact on well production. The dataincludes reservoir parameters, completion properties, opera-tional data from a step-rate test and main stimulation treat-ments — including fluid types, volumes, rates and pressures —fracture geometry details and monthly production data. Analy-ses of two areas are presented, Table 1. Area 1 represents amoderate reservoir with comparably better porosity and per-meability, while Area 2 consists of a tighter reservoir with a

The multistage fracturing (MSF) technique has considerablyimproved gas production from tight gas reservoirs all over theworld. Well production is one of the main determining factorsused to assess the success of a fracturing treatment. In this arti-cle, numerous vertical and horizontal wells drilled in high-pressure/high temperature heterogeneous reservoirs have beenevaluated to confirm the effectiveness of stimulation treatmentsand the benefits derived from the use of novel technologies.Among many variables that were analyzed are drilling, com-pletion and stimulation parameters, such as well azimuth,completion types, fluid characteristics, acid strength, etc.

A database for stimulated wells was created, and variousparameters were grouped and assessed to provide a correlationto, and understanding of, the effectiveness of fracture treatments,and to optimize development plans. Correlations were drawnby using the Pearson correlation coefficient (PCC) equation tocompute data trends and ensure good quality data. Numerousvery useful plots that show the different trends of the variablesevaluated and how they affect production rate have been con-structed and are presented here.

Analyses results indicate that use of real-time geomechanicsis important to predict reservoir pressure and mud weight whenwells are laterally drilled in the preferred minimum in situstress (σmin) direction. This is because when wells are drilledalong the σmin direction, they tend to become more unstabledue to the higher stress acting on the wellbore. Accuracy inpredicting stresses and pressures is key to the drilling of suchwells. The completion assemblies were selected between theopen hole multistage approach and the plug and perforationcased hole approach, based on reservoir properties and holeconditions. The impact on production performance of usingnon-damaging, low gel loading fracturing fluids, high strengthproppants, and optimal fluid and acid volumes is demon-strated using actual field examples. The application of channelfracturing, a novel fracturing technique, for improved fractureconductivity has proven successful for sustained gas produc-tion in tight gas reservoirs, thereby making low productivitywells commercially viable.

Impact of Multistage Fracturing on TightGas Recovery from High-Pressure/HighTemperature Carbonate Reservoirs

Authors: Dr. Zillur Rahim, Adnan A. Al-Kanaan, Dr. Hamoud A. Al-Anazi, Rifat Kayumov and Ziad Al-Jalal


Parameter Area 1 Area 2

Reservoir Characteristics Deep Deep

Porosity (%) 10.5 8

Permeability (mD) 1.2 0.5

Reservoir Temperature (°F) 260 300

Young’s Modulus (Mpsi) 6.5 6.4

FG (psi/ft) 0.87 0.98

Condensate to Gas Ratio (bbl/MMscf) 70 45

Table 1. Average reservoir properties for the selected areas


higher fracture gradient (FG). Vertical and horizontal wellswere evaluated in Area 1, and deviated — more than 50° incli-nation — and horizontal wells were analyzed in Area 2. Numerous parameters were evaluated to see their influence

on the gas rate (Qg) and productivity index (PI). The Qg andPI were normalized on the reservoir net height (Hnet) and theproduct of the Hnet and porosity (f ) for comparison. For hori-zontal wells, the Hnet was taken from the nearest vertical offsetwell. Due to the fact that no vertical wells were available inArea 2, the Hnet was taken from one of the deviated wells andassumed to be equal for all analyzed wells. This assumption isfair because all wells in Area 2 are located in close proximityto each other. The main focus of the study is to evaluate com-pletion, stimulation and reservoir parameters and their impactson well productivity. Many parameters were analyzed fromeach category, Table 2, some showing a visible effect on the PIand some not showing a clear trend. The parameters have been analyzed using the Pearson corre-

lation coefficient (PCC) calculated by the following equation:

(1)

where x and y are sets of independent parameters, x– and y– arethe average values. The PCC is a dimensionless index thatranges from -1.0 to 1.0 inclusive and reflects the extent of alinear relationship between two data sets. Figure 1 and Table 3provide examples of different PCC values. For this particularstudy, the PCC can be interpreted as described next.

TYPE OF WELL — VERTICAL VS. HORIZONTAL

A small reservoir section near the edge of the field was selectedfor Area 1, having horizontal wells completed with three-stage


multistage fracturing (MSF). These were compared with offsetvertical wells stimulated with single-stage acid fracturing. Thenormalized average PI for the horizontal wells was calculatedby PI/Hnet x f and clearly shows that the horizontal wells areproducing better compared to the offset vertical wells, Fig. 2(top). On average, the horizontal wells show an 85% increasein PI. In Area 2, results similar to those in Area 1 are observed,and on average the horizontal wells perform 60% better com-pared to the vertical wells.

OPEN HOLE LENGTH AND PERFORATED INTERVAL

Figure 2 (bottom) presents normalized PI values for verticaland horizontal wells in Areas 1 and 2, respectively, showing a

Fig. 1. Examples of different PCC values.

Completion Parameters

Well type: Vertical, horizontal, deviated

Contact length: Open hole (MSF), perforated (cement and cased)

Well azimuth: Deviation from maximum in situ stress (σmax) direction

Stimulation Parameters

Number of stages pumped without communication

Volume of acid per net pay

Pump rate

Pump time over overburden (OB) stress

Pump time above closure stress or FG but below OB

Treatment Evaluation Parameters

Etched fracture half-length

Average fracture width

T

Table 2. Evaluation parameters

PCC Values Comments

+ 0 ç 0.19 Very weak

+ 0.2 ç 0.39 Weak

+ 0.4 ç 0.59 Moderate

+ 0.6 ç 0.79 Strong

+ 0.8 ç 1 Very Strong

T Table 3. PCC values describing correlation strength

Fig. 2. PI for horizontal wells (top) and longer perforation/open hole intervals(bottom).


Area 2, more acid per foot of net pay is required because theincreased reservoir contact area is the key contributor for pro-ductivity enhancement in tight formations.

PUMP RATE

In this section, the average pump rate used during the mainacid fracturing treatment is analyzed. The wellbore fluid dis-placement at the beginning of treatment and the closed fractureacidizing stage at the end of the treatment are not considered,as they do not contribute to the actual well stimulation.

Figure 5 shows the pump rates and normalized PI values inArea 1 for vertical and horizontal wells. A somewhat good as-cending trend is observed as a function of the pump rate forthe PIs in the vertical wells (bottom, blue bars). The sharp in-crease in PI observed in two wells, Well-2 and Well-8, is due toother producing conditions, such as low drawdown pressure.The maximum average pump rate for the vertical wells is 50bbl/min, shown on the graph. The horizontal wells (red lineand bars) do not show a linear trend; well productivity in-creases with the pump rate at the beginning, but then it dropsafter the rate reaches about 35 bpm.

Although the industry rule of thumb in acid fracturing treat-ment calls for pumping at the highest possible rate to transportlive acid deeper into the created hydraulic fracture, the gain inlength is sometimes offset by the decrease in width. The etchedfracture width is vital to keep the induced fractures open dur-ing production, and therefore, the reduced fracture width canbe a possible reason for the productivity drop for wells treated

good increasing trend in productivity. The gain in PI is due tobetter communication when perforation lengths or open holesections are increased, allowing higher reservoir contact withthe wellbore. The open hole interval in a multistage comple-tion can also contribute to production if vertical permeabilityis favorable, although the major production comes through theinduced fractures.

ACID VOLUME

Different types of acid can be pumped during an acid fractur-ing treatment, such as gelled hydrochloric (HCl) acid withvarying concentrations, emulsified acid, self-diverting acid, etc.The type of acid is selected based on reservoir rock and fluidproperties. The volume of all pumped acid was recalculated toan equivalent volume of 28% HCl acid for comparison pur-poses. An average acid volume per stage was used for the hori-zontal wells.

Figure 3 illustrates the normalized PI graph (top) and showssomewhat nonlinear behavior in Area 1 for both vertical andhorizontal wells, suggesting that some optimum values of acidvolume exist and the optimum is not necessarily the maxi-mum. The corresponding acid volumes are also provided inFig. 3 (bottom). Analyses suggest that 500 gal to 600 gal of28% HCl acid equivalent per foot of net pay provides opti-mum well performance for vertical wells, and 300 gal/ft to 500gal/ft provides optimum well performance for horizontal wells.Larger acid volumes may not have a significant impact on frac-ture geometry and production as they may reduce the effective-ness of post-fracturing flow back due to the additional volumeof fluid introduced into the gas reservoir.

For Area 2, a good ascending trend of PI, further normalizedby the number of stages — productivity divided by the numberof stages — is observed, Fig. 4. For the tighter reservoirs of


Fig. 3. PI as a normalized function of acid pumped, Area 1 (top), and thecorresponding HCl acid volumes (bottom).

Fig. 4. PI as a function of acid pumped, Area 2.

Fig. 5. The separate PI values and average pump rates for horizontal and verticalwells, Area 1.


with the high average pumping rate. Based on this analysis, it isrecommended to limit the fracturing pump rate to 50 bbl/minin the study area.

Most of the wells in the tighter area, Area 2, were pumpedwith a pump rate of 35 bbl/min to 38 bbl/min, Fig. 6. Higherpump rates usually could not be achieved due to the higher insitu stresses encountered in this area compared to those inArea 1. A good ascending trend can be seen, with better pro-ductivity for wells pumped at a higher pumping rate.

PUMPING TIME AND BOTTOM-HOLE PRESSURE (BHP)

The BHP impacts the created fracture dimensions. In general,the higher the BHP, the larger the fracture size will be. If theBHP drops below the FG, the fracture will close. The overbur-den (OB) stress was calculated by multiplying the formation’strue vertical depth by an average OB stress gradient of 1.1 psi/ft.

Figures 7 and 8 show normalized PI values for vertical andhorizontal wells in Area 1 and Area 2, respectively. All wellsare placed in order of ascending value of pumping time, withBHP > OB in Area 1 or OB > BHP > FG in Area 2. A very sim-ilar trend to that of the previously analyzed average BHP is observed.

The PI decreases as BHP exceeds the OB stress, indicatingthe possible creation of T-shaped fractures causing limitedfracture growth. On the other hand, when the BHP is main-

tained below the OB stress, the fracture grows optimally andincreased PI is observed.

ETCHED FRACTURE HALF-LENGTH AND FRACTURE WIDTH

Normalized PI values were calculated for many horizontal andvertical wells in moderate to tight reservoir conditions. A goodpositive average productivity trend is observed in the tighterarea, Area 2, where horizontal wells are drilled, Fig. 9. There

is a nonlinear tread seen for vertical wells, where the produc-tivity increases up to a certain value (~170 ft) and then startsdecreasing. It may be that with longer fracture half-lengths,fracture widths are being compromised, thereby bringingdown the PI values. As for the width, Fig. 10, the vertical wells


Fig. 6. The combined PI values and average pump rates for both horizontal wells,Area 2.

Fig. 7. The PI values and pumping times with BHP > OB for vertical andhorizontal wells, Area 1.

Fig. 8. The PI values and pumping times with FG < BHP < OB for vertical andhorizontal wells, Area 2.

Fig. 9. Normalized PI values as a function of fracture half-length.

Fig. 10. Normalized PI values as a function of fracture width.


show a good increasing trend in PI values with wider fractures.For the horizontal well examples, the maximum PI is reachedfor a fracture width around 0.28”. A greater width attributesto reduced fracture length, which is also a very important parameter to achieve an improved production rate.

DRILLING AZIMUTH

Normalized PI values were calculated and plotted as a functionof well azimuth for horizontal, MSF wells. When wells deviatefrom the maximum in situ stress (σmax) direction, the createdfractures no longer stay parallel to the wellbore; they becomeoblique or transverse, thereby generating independent frac-tures. In the case of wells drilled toward the σmax direction, aninduced fracture is created along the wellbore. This restrictsthe independent growth of subsequent fractures.

Independent fractures are needed to provide more reservoircontact. The production rate is directly proportional to thecontact area, Fig. 11. Figure 12 presents the PI increase when

the number of stages is increased. For the Area 2 wells, thenumber of stimulation stages varied between one and four,whereas for Area 1, it varied between one and five. The im-proved PI numbers in both areas are noticeable.

SUMMARY

The PCC values were calculated for each set of variables to en-sure that the correlations are acceptable and the trends are cor-rect. The PCC numbers and correlation strength are providedin Table 4. With actual field data, which usually have inherent measurement errors, getting moderate to strong corre-lations is quite good and acceptable. This shows that the trendsreported in this article on the impact on PI and Qg, and deter-mining some of the optimal parameters, are valid in general.

CONCLUSIONS

This article presents the impact of many critical reservoir, com-pletion and stimulation parameters on well productivity. Thefollowing conclusions are derived from the work presented inthis article. These conclusions are specifically for the reservoirsstudied and may not be applicable as a general guideline.

• Horizontal wells with MSF completion provide better PI.

• Drilling longer laterals in the σmin direction provides anopportunity to design more stages for MSF completion,resulting in improved production.

• Preventing interstage communication is critical forproductivity optimization.

• For the vertical wells, longer perforated intervalsprovide better productivity.

• For the moderate quality reservoir, 500 gal to 600 gal of28% HCl acid equivalent per foot of net pay providesthe optimum well performance for vertical wells, and300 gal/ft to 500 gal/ft provides the optimum wellperformance for horizontal wells. For the tight reservoir,more acid per foot of net pay is recommended.

• A higher pumping rate positively affects production —


Fig. 11. Normalized PI values as a function of well azimuth.

Fig. 12. Normalized PI values as a function of the number of stimulation stages.

Table 4. The calculated PCC numbers and correlation strength

Variable PCC Correlation Strength

Type of Well 0.51 Moderate

Perforation Length 0.53 Moderate

Well Azimuth 0.93 Very strong

Number of Independent Stages 0.7 Strong

Acid Volume 0.58 (vertical) 0.38 (horizontal) Moderate and weak

Pump Rate 0.68 (vertical) -0.19 Strong and weak

BHP > OB -0.57 (vertical) -0.38 (horizontal) Moderate and weak

Open Hole > BHP > FG 0.38 (vertical) 0.23 (horizontal) Weak

T


but only up to about 50 bbl/min.

• Maintaining the correct BHP during acid fracturing iscritical; BHP should be kept high enough to overcomeclosure stress, but it must also be maintained below OBstress. This can be done by changing the pumping rate,changing the fluid viscosity, or in some instances,adjusting the pumping schedule during the treatment.

• For the moderate quality reservoir, analysis shows thatwell productivity increases with an increase in fracturehalf-length up to about 170 ft. For the tight reservoir,no constraint is observed for fracture length.

• An increase in the etched fracture width has positiveaffects on production. At the same time, the fracturehalf-length should not be compromised. The fracturehalf-length should be long enough to increase reservoircontact, but the fracture average width should be ashigh as possible to ensure that the fracture will remainopen at production conditions.

ACKNOWLEDGMENTS


This article was presented at the SPE Asia Pacific Unconven-tional Resources Conference and Exhibition, Brisbane, Aus-tralia, November 9-11, 2015.

REFERENCES

1. Al-Jallal, I.A.: “Diagenetic Effects on Reservoir Propertiesof the Permian Khuff Formation in Eastern Saudi Arabia,”SPE paper 15745, presented at the SPE Middle East OilShow, Manama, Bahrain, March 7-10, 1987.

2. Bukovac, T., Nihat, M.G., Leal Jauregui, J., Malik, A.R.,Bolarinwa, S. and Al-Ghurairi, F.: “Stimulation Strategiesto Guard against Uncertainties of Carbonate Reservoirs,”SPE paper 160887, presented at the SPE Saudi ArabiaSection Technical Symposium and Exhibition, al-Khobar,Saudi Arabia, April 8-11, 2012.

3. Rahim, Z., Al-Anazi, H.A., Al-Kanaan, A.A., Makmum,A., Fredd, C.N. and Gurmen, M.N.: “Evolving KhuffFormation Gas Well Completions in Saudi Arabia:Technology as a Function of Reservoir CharacteristicsImproves Production,” SPE paper 163975, presented at theSPE Unconventional Gas Conference and Exhibition,Muscat, Oman, January 28-30, 2013.

4. Ahmed, M., Rahim, Z., Al-Anazi, H.A., Al-Kanaan, A.A.and Mohiuddin, M.: “Development of Low PermeabilityReservoir Utilizing Multistage Fracture Completion in theMinimum Stress Direction,” SPE paper 160848, presentedat the SPE Saudi Arabia Section Technical Symposium andExhibition, al-Khobar, Saudi Arabia, April 8-11, 2012.


BIOGRAPHIES

Dr. Zillur Rahim is a Senior PetroleumEngineering Consultant with SaudiAramco’s Gas Reservoir ManagementDepartment (GRMD). He heads theteam responsible for stimulationdesign, application and assessment forconventional and tight gas reservoirs.

Rahim’s expertise includes well stimulation, pressuretransient test analysis, gas field development, planning,production enhancement and reservoir management. Heinitiated and championed several new technologies in wellcompletions and hydraulic fracturing for Saudi Arabia’snonassociated gas reservoirs.

Prior to joining Saudi Aramco, Rahim worked as aSenior Reservoir Engineer with Holditch & Associates,Inc., and later with Schlumberger Reservoir Technologies inCollege Station, TX, where he consulted on reservoirengineering, well stimulation, reservoir simulation,production forecasting, well testing and tight gasqualification for national and international companies.Rahim is an instructor who teaches petroleum engineeringindustry courses, and he has trained engineers from theU.S. and overseas. He developed analytical and numericalmodels to history match and forecast production andpressure behavior in gas reservoirs. Rahim also developed3D hydraulic fracture propagation and proppant transportsimulators, and numerical models to compute acidreaction, penetration, proppant transport and placement,and fracture conductivity for matrix acid, acid fracturingand proppant fracturing treatments. He has authored morethan 90 technical papers for local/international Society ofPetroleum Engineers (SPE) conferences and numerous in-house technical documents. Rahim is a member of SPE anda technical editor for SPE’s Journal of Petroleum Scienceand Technology (JPSE) and Journal of PetroleumTechnology (JPT). He is a registered Professional Engineerin the State of Texas, and a mentor for Saudi Aramco’sTechnologist Development Program (TDP). Rahim teachesthe “Advanced Reservoir Stimulation and HydraulicFracturing” course offered by the Upstream ProfessionalDevelopment Center (UPDC) of Saudi Aramco.

He is a member of GRMD’s technical committeeresponsible for the assessment, approval and application ofnew technologies, and he heads the in-house servicecompany engineering team on the application of best-in-class stimulation and completion practices for improvedgas recovery.

Rahim has received numerous in-house professionalawards. As an active member of the SPE, he hasparticipated as co-chair, session chair, technical committeemember, discussion leader and workshop coordinator invarious SPE international events.

Rahim received his B.S. degree from the InstitutAlgérien du Pétrole, Boumerdes, Algeria, and his M.S. andPh.D. degrees from Texas A&M University, CollegeStation, TX, all in Petroleum Engineering.

Rahim’ expertise includes


Adnan A. Al-Kanaan is the Managerof the Gas Reservoir ManagementDepartment (GRMD), where heoversees three gas reservoirmanagement divisions. Reporting tothe Chief Petroleum Engineer, Adnan isdirectly responsible for making

strategic decisions to enhance and sustain gas delivery tothe Kingdom to meet its ever increasing energy demand. Heoversees the operating and business plans of GRMD, newtechnologies and initiatives, unconventional gas developmentprograms, and the overall work, planning and decisionsmade by his more than 120 engineers and technologists.

Adnan has 20 years of diversified experience in oil andgas reservoir management, full field development, reservesassessment, production engineering, mentoring of youngprofessionals and effective management of large groups ofprofessionals. He is a key player in promoting and guidingthe Kingdom’s unconventional gas program. Adnan alsoinitiated and oversees the Tight Gas Technical Team toassess and produce the Kingdom’s vast and challengingtight gas reserves in the most economical way.

Prior to the inception of GRMD, he was the GeneralSupervisor for the Gas Reservoir Management Division underthe Southern Reservoir Management Department for 3 years,heading one of the most challenging programs in optimizingand managing nonassociated gas fields in Saudi Aramco.

Adnan started his career at the Saudi Shell PetrochemicalCompany as a Senior Process Engineer. He then joinedSaudi Aramco in 1997 and was an integral part of thetechnical team responsible for the on-time initiation of thetwo major Hawiyah and Haradh gas plants that currentlyprocess more than 6 billion standard cubic feet (bscf) ofgas per day. Adnan also directly managed Karan and Wasitfields — two major offshore gas increment projects — withan expected total production capacity of 5 bscf of gas perday, in addition to the new Fadhili gas plant with 2.5 bscfper day processing capacity.

He actively participates in the Society of PetroleumEngineers (SPE) forums and conferences, and has been akeynote speaker and panelist for many such programs.Adnan’s areas of interest include reservoir engineering, welltest analysis, simulation modeling, reservoir charac-terization, hydraulic fracturing, reservoir developmentplanning and reservoir management.

In 2013, he chaired the International PetroleumTechnical Conference, Beijing, China, and in 2014, Adnanwas a keynote speaker and technical committee member atthe World Petroleum Congress, Moscow, Russia. In 2015,he served as Technical Conference Chairman and ExecutiveMember at the Middle East Oil Show, Bahrain.

Adnan received the international 2014 Manager of theYear award conferred by Oil and Gas Middle East magazineand is the recipient of the 2015 SPE Regional Award.

He has published more than 40 technical papers onreservoir engineering and hydraulic fracturing.

Adnan received his B.S. degree in Chemical Engineeringfrom King Fahd University of Petroleum and Minerals(KFUPM), Dhahran, Saudi Arabia.


Dr. Hamoud A. Al-Anazi is theGeneral Supervisor of the NorthGhawar Gas Reservoir ManagementDivision in the Gas ReservoirManagement Department (GRMD).He oversees all work related to thedevelopment and management of huge

gas fields like Ain-Dar, Shedgum (SDGM) and ‘Uthmaniyah(UTMN). Hamoud also heads the technical committee thatis responsible for all new technology assessments andapprovals for GRMD. He joined Saudi Aramco in 1994 asa Research Scientist in the Research & Development Centerand moved to the Exploration and Petroleum EngineeringCenter – Advanced Research Center (EXPEC ARC) in2006. After completing a one-year assignment with theSouthern Area Reservoir Management Department,Hamoud joined the GRMD and was assigned to supervisethe SDGM/UTMN Unit and more recently the Hawiyah(HWYH) Unit. With his team, he successfully implementedthe strategy of deepening key wells that resulted in the newdiscovery of the Unayzah reservoir in UTMN field and theaddition of Jauf gas reserves in HWYH field. Hamoud wasawarded a patent application published by the U.S. Patentand Trademark Office on September 26, 2013.

Hamoud’s areas of interest include studies of formationdamage, stimulation and fracturing, fluid flow in porousmedia and gas condensate reservoirs. He has publishedmore than 60 technical papers at local/internationalconferences and in refereed journals. Hamoud is an activemember of the Society of Petroleum Engineers (SPE), wherehe serves on several committees for SPE technicalconferences. He is also teaching courses at King FahdUniversity of Petroleum and Minerals (KFUPM), Dhahran,Saudi Arabia, as part of the Part-time Teaching Program.

In 1994, Hamoud received his B.S. degree in ChemicalEngineering from KFUPM, and in 1999 and 2003, hereceived his M.S. and Ph.D. degrees, respectively, inPetroleum Engineering, both from the University of Texasat Austin, Austin, TX.

strategic decisions to gas fields like Ain-Dar


Rifat Kayumov started his careerworking in the ProductionEnhancement Department for one ofthe Russian service companies inwestern Siberia. In August 2004, hejoined the Well Services Division inSchlumberger. Rifat spent 3 years

working in western Siberia, then 6 years in the Volga-Uralsregion of Russia in different technical positions. In June2013, he was moved to Saudi Arabia as the ProductionStimulation Engineer in charge of stimulation activities forSaudi Aramco. Rifat’s main focus as a Technical Engineer issupporting hydraulic fracturing and matrix acidizingoperations.

He is the author of 10 technical papers published by theSociety of Petroleum Engineers (SPE) and the InternationalPetroleum Technology Conference (IPTC).

In 1999, Rifat received his B.S. degree in MechanicalEngineering from the Russian State University of Oil andGas, Moscow, Russia.

Ziad Al-Jalal is currently working asthe Stimulation Domain Manager forSchlumberger, where he is involved infracturing projects in Saudi Arabia andBahrain. He has 15 years of experiencein fracturing treatments in bothconventional and unconventional

wells. Ziad joined Schlumberger in 2000, working as aFracturing Field Engineer in western Siberia, Russia, for 4years, then as a Technical Engineer in Saudi Arabia. From2008 to 2012, he was a Team Leader in the Tight GasCenter of Excellence based in Dhahran, Saudi Arabia. Ziadpreviously worked as a Senior Production and StimulationEngineer in Oklahoma City, OK, from 2012 to 2014.

He received his B.S. degree in Mechanical Engineeringfrom King Fahd University of Petroleum and Minerals(KFUPM), Dhahran, Saudi Arabia, in 1999.

working in western Siberia,

wells. Ziad joined Schlumberger



ABSTRACTmultilateral horizontal well technologies have demonstratedincreased production rates. Several multilateral configurationshave been drilled, with four to seven legs, for both producerand injector wells1. Well architecture and completion becamethe focus of many innovative technologies that increased wellreservoir contact. Simultaneously, advanced completions weresought to reduce field development costs by reducing the totalnumber of wells required to achieve production targets2, 3.

In the Kingdom of Saudi Arabia, multilaterals have beendrilled for decades. From this concept, Saudi Aramco movedto successfully implement maximum reservoir contact wells tofurther enhance hydrocarbon recovery4, 5. From there, SaudiAramco has been developing extreme reservoir contact wellswhere control and monitoring measures are deployed in boththe motherbore and the laterals6. Lateral accessibility is an im-portant aspect of these advanced completion concepts. Severalmethods and tools have been developed to facilitate lateral ac-cessibility, making changes to existing completion types andtools7-11; however, active sensing and accurate mapping of thelateral window required further improvement through new intervention tools.

In this article, a new lateral accessibility tool, the well lateralintervention tool (WLIT), is presented. This tool is a joint development between Saudi Aramco and Welltec. Several fieldtrial tests have been successfully performed in Saudi Aramcofields, which have proven the concept of smart lateral sensingand access using several sets of advanced sensors and diagnostictools.

WLIT COMPONENTS AND SPECIFICATIONS

The first version of the WLIT introduced was “wired” due tothe fact that the third party tool has to be modified with a wirefeed to be able to communicate commands to the WLIT steeringjoint — at the very bottom section of the string — and allowsteering of the toolstring in the desired direction for lateral access-ing. This version proved the concept in the first two trials,where a multiphase production logging tool was deployed andsuccessfully accessed the laterals. With the lessons learned fromthe first two trials, stage 2 development commenced to introducethe “wireless” WLIT. The wireless WLIT is basically equippedwith a wireless sub to allow the WLIT to send commands to

Wells with extended reach, or multilateral wells, have im-proved reservoir contact and have opened the opportunity forwell placement and drilling optimization. Since the early2000s, the number of maximum reservoir contact wells has increased substantially, and the benefit of these wells is beingrealized at the early implementation stage. To enhance the per-formance of these multilateral wells, intervention operations inthe laterals are required. Stimulation, data acquisition andother operations help to optimize the production from the lat-erals; however, accessing the lateral of any wellbore for inter-vention in a reliable manner is still a challenge.

This article describes the development of an intelligent, real-time controllable tool, the well lateral intervention tool(WLIT), that can identify a lateral junction and steer an inter-vention/surveillance string into it. The WLIT is designed to bedeployed utilizing either coiled tubing (CT) or e-line (with thehelp of Well Tractor® for extended reach horizontal deploy-ments) for logging and/or stimulation purposes. This tool provides the ability to increase the quantity and quality of in-formation collected from the whole well — the motherboreand each of the multiple laterals individually — to get the bestanswers for intervention planning. The discussion here is dedi-cated to the development stages of the tool and the field trialtests results.

The WLIT comes in two versions; the first version is“wired,” which accommodates specific logging tools that arecompatible with the WLIT design, and the second version is“wireless,” which allows the use of all types of logging tool-strings from any third party provider. The test results are fromtrials using both versions of the tool. The WLIT sensory equip-ment as well as the control environment are described, and results from the field trial tests are presented.

INTRODUCTION

The oil and gas industry is constantly advancing well technolo-gies to increase recovery and reduce production costs, espe-cially as more and more complex reservoirs are being targeted.The idea of increasing reservoir contact with multilateral com-pletions started in the 1990s, and since the first completions,

Development and Field Trial of the Well Lateral Intervention Tool

Authors: Dr. Mohamed N. Noui-Mehidi, Abubaker S. Saeed, Haider Al-Khamees and Mohamed Farouk



the steering joint without the need for modifying the thirdparty tool, given that some third party tools don’t have enoughspace to accommodate the extra wiring required. The new so-lution was deployed in the rest of the trials.

The tool itself is an electromechanical platform comprisingseveral components: the sensor package with different types ofsensors; the electromechanical actuator system, which actuatesin the direction desired to allow steering of the tool toward thelateral; and the wireless sub and control/monitoring interface.Figure 1 provides a diagram of the WLIT, and Table 1 summa-rizes the main features.

In the following sections, the different parts of the WLITtool are described.

Sensor 1: Well Hardware Scanner

The well hardware scanner (WHS) is designed to detect themagnetic characteristics of known reference points on the cas-ing string; these points can be used to determine the positionof the entrance to a lateral window. The WHS consists of per-manent magnets and magnetic sensors. The magnets and mag-netic sensors are placed in a grid-like structure that ensureswell-defined magnetic flux lines. The sensors measure changesto the magnetic field caused by changes in the metallic sur-rounding, i.e., indicating casing collars, perforation holes, slid-ing sleeves, etc. In this arrangement, the results are monitoredand the tool is controlled from the surface using the control


cockpit. The sensor measures the angle of a magnetic field rel-ative to the sensitive axis — the direction crosswise to the sen-sor. Each of the sensors measures the anomaly of a magneticfield relative to a given direction. When the tool is positionedin the casing, the changes in geometry/metallic surroundingwill cause changes in the magnetic field. The sensors record thesame fluctuations in the signals when passing the same geo-metric/metallic structures in the well. As an illustration of theconcept, Fig. 2 shows a typical signal response received fromthis sensor.

The WHS diagnostic tool provides the following:

• Depth measurement.

• Lateral entry confirmation.

• Lateral window identification.

• Inclination (in real time).

Fig. 1. A sketch of the WLIT tool assembly. This includes a well tractor toillustrate the assembly when a well tractor is needed in the operation.

OD 2⅛”

Length (w/o third party tool or well tractor)

32 ft

Length with Well Tractor 80 ft*

Weight in Air 220 lb

Maximum Pressure 20,000 psi

Maximum Temperature 257 °F

Tensile Strength 36,000 lb

Compressive Strength 30,000 lb

Well Fluid Oil/Water/Gas

Minimum Dev. at Junction 30°

Maximum ID at Junction8½” Cased Hole or

Open Hole

Third Party Tool Requirement Mono Conductor

* Depending on desired confi guration; third party tool will depend on logging tool utilized.

Table 1. WLIT specifications

Fig. 2. Raw data from the WHS indicating the tool response to the changes in themetallic surrounding environment (welds, holes, etc.), shown above the plot.


The WUS diagnostic tool provides the following:

• Lateral window identification.

• Lateral entry confirmation.

• Tool orientation.

• Inclination (in real time).

• Open hole/cased hole and open hole/open holedistinction.

The Wireless Sub

The wireless sub was designed to allow communication withthe steering joint without the need to modify the third partytools. It is operated from the surface and uses batteries to pro-vide the power required to activate and steer the steering joint.The batteries are designed to work for 12 hours downhole forthe same run. The wireless kit has a data protocol converter toconnect to the wireless hub, Fig. 4.

The Electromechanical Actuator (Steering Joint)

Data from the sensor package, which is coupled with priorwell path information, is used to maneuver the electromechan-ical actuator section, Fig. 5, into the lateral in two steps. Thefirst step pivots the joint around its central axis in the directiontoward the center of an identified lateral. In the second step, ahydraulic piston steers the joint in the desired direction; steer-ing is done in increments of 15° to fine-tune access. The steer-

• Tool speed/direction.

• Open hole/cased hole distinction.

Sensor 2: Well Ultrasonic Scanner

The well ultrasonic scanner (WUS) is designed to be used insingle-phase flow regimes, mainly liquid. It is able to providefast, reliable and accurate range detection in that environment.It consists of an array of ultrasonic transducers arranged cir-cumferentially around the outer diameter (OD) of the tool,facing outwards. The tool transmits individual signals in se-quence while “listening” simultaneously on all transducers.The echo return time and amplitude response provide informa-tion — a wellbore fingerprint — identifying the surroundingenvironment.

In principle, it uses basic range finding principles of time offlight measurements for ultrasonic signals, Fig. 3a. The meas-urements can be made using either one or two transducers. Itmay be possible to acquire the speed of sound of the well fluidin real time while operating in the well. To do so requires sam-pling the fluid once or repeatedly for calibration. Software atthe surface is designed to interpret/plot the transmitted/re-ceived signal and find the place of diverging radius, i.e.,washouts and sidetracks. Basically, the WUS transducers,placed around the circumference of the tool, are able to mapthe inside OD of the opposite wall. Figure 3b illustrates howthe sensors show an opening space in the pipe on the right-hand side where the reflected ultrasonic data is far off from thedata received directly from the pipe wall.

Fig. 3. (a) An ultrasonic scanner range measurement example in a slotted casing. (b) Recorded data showing an open space in the pipe (right-hand side) where the reflectedultrasonic data is far off from the data received directly from the pipe wall.

Fig. 4. The wireless sub function.



able joint was developed to be controlled from the surface us-ing the data from the sensor package. The control system isused to engage and disengage the various tools in the toolstring.

Once an angle value has been set, the arm rotates to the de-sired direction, one that points toward the lateral entry. Steer-ing then commences, and after the tool has been confirmed inthe lateral, the controller at the surface releases the arm to itsneutral point, which will deactivate it.

The toolstring, once in the lateral, progresses while the armis deactivated.

The Software and the Interface (Selective Access Interface)

The WLIT utilizes software that is run on an interface at thesurface, where it is operated by the field engineer. The softwarecontrols and monitors the entire operation of all the tools, aswell as two sub modules specific for the intervention tool: (a)Module 1 incorporates the data from the sensor package toconsistently display a proximity signal showing the casing/pipe/tubing/liner in a 360° circumference, and (b) Module 2controls the electromechanical actuator.

The signal response and the tool responses are monitored inreal time for accurate depth control and operational efficiency.

TRIAL TEST SUMMARY

The WLIT was designed to be compatible with deployment byeither an e-line or coiled tubing (CT) that uses an e-line tolower power transmission to the sensors. Since the lateral win-dow shape and integrity are unknown, it was decided to exe-cute all trials utilizing CT for simplicity and to prove the

concept of the WLIT. The tool was tested in seven wells inSaudi Arabia; some had been completed with a cased holemotherbore and open hole laterals and others had been com-pleted with an open hole motherbore and open hole laterals.The main objective of the trials was to prove the tool’s capabil-ity to map/scan the motherbore at lateral depths, using the sen-sor package to identify the depth and direction of the lateralwindow, and then to guide the bottom-hole assembly to accessany desired lateral. Once a lateral window is scanned, the logfile can be used at any time later to access the lateral withoutthe need to re-scan the motherbore. Scanning and accessingprocedures were identical for all wells. One well example isdiscussed next; all well trial configurations are summarized inTable 2.

Trial Test of Well-1: Operational Details

Figure 6 shows the lateral intervention toolstrings deployed forboth jobs. The first test took place in Well-1, Fig. 7, where thetool was deployed on a third party CT string. The primary ob-jective was to map the motherbore, determine where the lat-eral windows were and then drive the toolstring from thecased hole motherbore into the open hole laterals. The WLITwas run in hole, and logging data of the sensors’ signals werecollected at the surface on the control computer. The toolstringstarted logging 7,000 ft above the topmost lateral (L3) win-dow. The WHS sensor clearly indicated the casing housing andthe different parts of the well completion as expected. At thevicinity of L3, the sensors indicated a change in the signal am-plitude that revealed the presence of the lateral window. Oncethe toolstring passed the window, the sensor’s signal went backto the previous signal range, indicating normal casing in themotherbore. The motherbore mapping continued down to-ward the two other laterals, and at the vicinity of each lateral,the same signal deviation was observed, indicating the pres-ence of the lateral windows.

The toolstring was pushed further down into the mother-bore to the open hole section where it was clearly seen that the

Fig. 5. The electromechanical actuator (steering joint).

Well Number WLIT Version Number of Laterals Completion Type*

Well 1 Wired MB – 3 × L Cased Hole-Open Hole

Well 2 Wired MB – 1 × L Cased Hole-Open Hole

Well 3 Wireless MB – 2 × L Cased Hole-Open Hole and Open Hole-Open Hole

Well 4 Wireless MB – 1 × L Open Hole-Open Hole

Well 5 Wireless MB – 1 × L Cased Hole-Open Hole



* CH-OH/OH-OH going from cased hole to open hole/Going from open hole to open hole

Table 2. The configurations for the WLIT test wells (MB: Motherbore; L: Lateral; Cased Hole-Open Hole: Going from cased hole to open hole; Open Hole-Open Hole:Going from open hole to open hole).



signal was completely lost, again as anticipated, since this impliedthe absence of any metallic surrounding, which is true for anopen hole section. The toolstring was then pulled back alongthe motherbore, and the three lateral windows were mappedagain while moving the WLIT back toward the well heel.

Figure 8 shows a typical WHS signal response indicating alateral window signature; the large amplitude results from theloss of signal that occurs with the interruption in the metallicsurrounding at the lateral junction. Before entering any of thelaterals, the toolstring was run at a slow speed several timesbackwards and forwards in the vicinity of the window to al-low the sensors to more clearly identify the entry point’s az-imuth. The responses of multiple sensors from multiple passeswere then combined to better locate the window width andwindow orientation, Fig. 9. The lateral window shown in Fig.


Fig. 7. Schematic of Well-1 used for the first field trial.

9 corresponds to the window mapped in Well-1. The signalclearly identifies the window extension from both sides, andthe window orientation can be seen on the vertical axis. Oncethe lateral junction window was successfully mapped, the lat-eral entry preparation started by pulling the toolstring 30 ftabove the lateral window, powering up the electromechanicalactuator and changing its orientation to point toward the lat-eral window, i.e., 315° (45° from the left) for L2 in Well-1.

While powering the electromechanical actuator, the engineerreceived a positive indication at the surface that the arm hadrotated to the desired set azimuth. The toolstring was then runat the same slow speed while passing the window. Initiallywhile passing the window, the signal indicates a large amplitudechange in the magnetic flux. As the toolstring moves furtherahead into the lateral, the signal amplitude decreases until thesignal disappears completely, indicating it is in an open holeenvironment, Fig. 10. During the field trial, the toolstring wasrun several hundred feet further into the open hole lateral. Asanticipated, the signal never restarted. After progressing 200 ft

Fig. 6. The lateral intervention toolstrings used in the field trials.

Fig. 8. WHS sensor window signature during the motherbore logging.

Fig. 9. Lateral window azimuthal indications after several passes across thesame window (the more passes taken the darker the area, i.e., a confirmedwindow opening).


into the lateral, the toolstring was pulled back to the junctionto test the response. The signal returned at the same locationwhere it had been lost due to the presence once again of thecasing. The operation was repeated several times to assure re-peatability of the signal. At each run and at each lateral, thesame results were obtained, indicating correct and positive lat-eral entrance and exit. The access was performed at differentspeeds, between 5 ft/s to 15 ft/s.

During the mapping and lateral entry procedures, the engi-neer can analyze the response from the complementary combi-nation of tool signals, as previously described. Therefore, tomake sure that the lateral was accessed before moving thetoolstring deeper in the lateral open hole, multiple signals werecompared while passing the window and while trying to accessthe lateral, Figs. 11 and 12. In Fig. 11 it can be seen that twoindependent passes for the same lateral window gave the samesignal responses, while in Fig. 12 the comparison of the signalwhile passing the window and while entering the lateral are

completely different. The two signals in Fig. 12 deviated just atthe depth where the window started, indicating the high prob-ability of a lateral intersection. The toolstring then progressedfurther into the lateral open hole until the signal was com-pletely lost at around 49 ft from the entry point — enough dis-tance to lose the response from the casing — again indicatingthat the sensors had moved deep into the open hole.

Open Hole-Open Hole Laterals

In the open hole-open hole lateral completions — open holemotherbore to open hole lateral — the WHS response will bezero due to the absence of any metallic surrounding. There-fore, the WUS (Sensor 2) response is used alone to identify andconfirm lateral accessing. During the scanning passes, the WUSgives a real-time measurement of the borehole inclination —motherbore and lateral.

In Fig. 13, plots of the inclination data of the WUS in real-time measurement vs. data from a drilling survey are shown.The overlay of the real-time measurement with the drilling survey would confirm the location of the toolstring — whetherin the motherbore or in the lateral.


Fig. 10. WHS signal loss as the toolstring enters the open hole lateral.

Fig. 11. The sensor response for two different passes across the same lateralwindow. The two signals are clearly seen as being overlaid.

Fig. 12. The sensor response comparison for two different passes; one passing awindow and one accessing a lateral. It can be seen that the two signals aredifferent, indicating lateral entry.


CONCLUSIONS

Lateral accessibility with the WLIT has been proven throughseveral well trials in both cased hole to open hole and openhole to open hole well configurations. This tool is the firstelectromechanical downhole tool in the industry for both lat-eral detection and repeatable access. The sensor package of thetool can visualize the lateral window as well as direct the tool-string toward the lateral entry point. The sensors have shownvery good reliability in identifying the lateral junction windowshape and orientation, and they have been used several timessuccessfully to access laterals.

The WLIT is a tool designed to suit both e-line and CT withan e-line deployment for logging; the potential exists to use thetool for future acid stimulation purposes. The wireless commu-nication provides the capability to deploy a wide range of sur-veillance tools with different service providers. This tool givesoperators the ability to locate and enter laterals, overcomingprevious limitations in the industry and allowing the operatorto fully understand and remediate lateral monitoring.

ACKNOWLEDGMENTS

The authors would like to thank the management of SaudiAramco and Welltec for their support and permission to pub-lish this article, as well as thank the production engineeringand operations teams involved. In addition, the authors wouldlike to acknowledge the help of the following individuals andtheir respective teams in the accomplishment of this work:Mohannad Abdelaziz, Wessam Busfar, Talha Ahmed, MichaelBlack, Brian Roth, Ahmed Zain and Marwan Zarea.

This article was previously published in SPE Productionand Operations, April 2015.

REFERENCES

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Controlled Hydraulic Interval Control Valves for theManagement of Water Production in the Saih Rawl Field,Sultanate of Oman,” OTC paper 15134, presented at theOffshore Technology Conference, Houston, Texas, May 5-8, 2003.

2. Ramakrishnan, T.S.: “On Reservoir Fluid Flow Controlwith Smart Completions,” SPE Production & Operations,Vol. 22, No. 1, February 2007, pp. 4-12.

3. Artus, V., Durlofsky, L.J., Onwunalu, J. and Aziz, K.:“Optimization of Nonconventional Wells underUncertainty Using Statistical Proxies,” ComputationalGeosciences, Vol. 10, No. 4, December 2006, pp. 389-404.

4. Salamy, S.P., Al-Mubarak, H.K., Hembling, D.E. and Al-Ghamdi, M.S.: “Deployed Smart Technologies Enablers forImproving Well Performance in Tight Reservoirs — Case:Shaybah Field, Saudi Arabia,” SPE paper 99281, presentedat the Intelligent Energy Conference and Exhibition,Amsterdam, The Netherlands, April 11-13, 2006.

5. Al-Arnaout, I.H., Al-Zahrani, R.M., Jacob, S. and Kumar,S.: “Smart Wells Experiences and Best Practices at HaradhIncrement-III, Ghawar Field,” SPE paper 105618,presented at the SPE Middle East Oil and Gas Show andConference, Manama, Bahrain, March 11-14, 2007.

6. Qahtani, A.M. and Dialdin, H.: “SS: AdvancedCompletion Technologies Maximize Recovery,” OTCpaper 20136, presented at the Offshore TechnologyConference, Houston, Texas, May 4-7, 2009.

7. Hovda, S., Haugland, T., Waddell, K. and Leknes, R.:“World’s First Application of a Multilateral SystemCombining a Cased and Cemented Junction with FullboreAccess to Both Laterals,” SPE paper 36488, presented atthe SPE Annual Technical Conference and Exhibition,Denver, Colorado, October 6-9, 1996.

8. Antczak, E.J., Smith, D.G.L., Roberts, D.L., Lowson, B.and Norris, R.: “Implementation of an AdvancedMultilateral System with Coiled Tubing Accessibility,” SPEpaper 27673, presented at the SPE/IADC DrillingConference, Amsterdam, The Netherlands, March 4-6,1997.

9. Rivenbark, W.M., Al-Sowayigh, M.I. and Al-Furaidan,Y.A.: “A New Selective Lateral Re-Entry System,” SPEpaper 59209, presented at the IADC/SPE DrillingConference, New Orleans, Louisiana, February 23-25,2000.

10. Dahroug, A., Al-Marzooqi, A., Al-Ansara, F., Chareuf, A.and Hassan, M.: “Selective Coiled Tubing Access into Multilateral Wells in Upper Zakum Field: A Two-Well Case Study from Abu Dhabi,” SPE paper 81716, presented at the SPE/ICoTA Coiled Tubing Conference and Exhibition, Houston, Texas, April 8-9, 2003.

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Fig. 13. Inclination plot (drilling survey vs. WUS measurement).


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BIOGRAPHIES

Dr. Mohamed N. Noui-Mehidi is aPetroleum Engineer Consultant atSaudi Aramco’s Exploration andPetroleum Engineering Center –Advanced Research Center (EXPECARC). He has been covering theposition of champion of multiphase

flow metering and well intervention for the ProductionTechnology Team. Mohamed joined Saudi Aramco in late2008 and had previously been working for the Common-wealth Scientific and Industrial Research Organization,Australia. He has more than 25 years of experience in thearea of multiphase flow dynamics, flow metering and flowmodeling.

Mohamed’s research activities are related to thedevelopment of new technologies in well control andmonitoring for upstream oil and gas production. He haspublished more than 90 journal articles and conferencepapers on the different aspects of fundamental and appliedfluid dynamics as well as authored six company grantedpatents and several patent applications.

Mohamed received his Ph.D. degree in Resource &Energy Science from the University of Kobe, Kobe, Japan.

Abubaker S. Saeed joined SaudiAramco in 2011 as a PetroleumEngineer, working in the sensing andintervention focus area of theProduction Technology Team in theExploration and PetroleumEngineering Center – Advanced

Research Center (EXPEC ARC). He has published eightpatents and several technical and journal papers, and ledthe successful field deployment of several new interventiontechnologies.

Abubaker has been a recipient of several internationalawards, including the “2015 Best Young Oil and GasProfessional of the Year” award as well as the prestigious“2015 Young ADIPEC Engineer of the Year” award. Hisproject work in the area of downhole sensing and inter-vention was awarded the ICoTA Intervention TechnologyAward of 2014, as well as being nominated as a finalist forthe World Oil Awards 2014 — Best ProductionTechnology.

Abubaker received his B.S. degree in SystemsEngineering from King Fahd University of Petroleum andMinerals (KFUPM), Dhahran, Saudi Arabia. He receivedhis M.S. degree in Mechanical Engineering from KingAbdullah University of Sciences and Technology, Thuwal,Saudi Arabia.

flow metering and well

Research Center (EXPEC

Haider Al-Khamees is currently theCountry Manager at QuinterraTechnologies. He previously worked atWelltec, in the area of well interventionand field services. Haider has 7 years ofexperience in well interventiontechnologies and logging operations.

His previous experience also included a short periodworking at Schlumberger.

In 2003, he received his B.S. degree in PetroleumEngineering from King Fahd University of Petroleum andMinerals (KFUPM), Dhahran, Saudi Arabia.

Mohamed Farouk joined Schlumbergerin 1991 as a Field Engineer in Egypt. In1995 he was the first DESC Engineerplaced by Schlumberger at SaudiAramco working in the ‘UthmaniyahProduction Engineering Department. In1996, Mohamed was transferred to

Schlumberger’s Training Center in the U.K. as the WellIntervention Technical Instructor where he worked with ateam of qualified instructors on writing online manuals forboth technical and operational training. Upon completionof this project in 1999, Mohamed was transferred to Egyptas the Well Intervention Area Manager for the East AfricaMarket. He also acted as the technical focal point for thecoiled tubing services in the Middle East. In 2001,Mohamed moved to Saudi Arabia as a Well ConstructionManager, working there for 3 years. He introduced thelightweight cement systems to Saudi Aramco by workingclosely with Saudi Aramco’s Fluids Division of the R&DCenter.

In 2005, Mohamed was assigned the role of MarketingManager for the Gulf Area for Well Intervention,Cementing and Stimulation Business. During thisassignment, he worked closely with national oil companies(NOCs) on value added projects and services byintroducing new technology solutions. Mohamed’s lastassignment with Schlumberger was as the Middle EastRegion Well Intervention Manager in the company’s headoffice in Dubai, UAE.

He joined Welltec in 2011 as the Middle East andNorth Africa Vice President, staying in that position untilJanuary 2015. While in this role, Mohamed managed tointroduce multiple “firsts” in the world of e-linemechanical technologies to several NOCs, as well asinternational oil companies (IOCs). These included: wellobstruction milling, a multilateral steering tool, open holetractoring solutions and coiled tubing tractoring in openholes. He is currently the Middle East and Africa RegionManager for Well Intervention, Cementing and StimulationBusiness with Weatherford.

In 1991, he received his B.S. degree in Civil Engineeringfrom Ain Shams University, Cairo, Egypt.

His previous experience

Schlumberger’s Training Training T


ABSTRACTdownhole tools by using the casing as the drillstring. Likedrillpipe, the casing string conveys torque, rotation and hy-draulic energy to the bit. The directional casing while drilling(DCwD) solution can be used with any conventional direc-tional or logging bottom-hole assembly (BHA), while ensuringthat every foot drilled is cased off and secured1.

One of the benefits of the casing while drilling technology isan augmented wellbore strengthening2. As a result, the well-bore retains a smoother, more uniform surface, thereby provid-ing stability as well as minimizing the invasion of the drillingfluid into the surrounding near wellbore area3. This aspectalone can reduce the likelihood of differential sticking and im-prove cementing quality4.

Throughout the casing while drilling process, the operatorshould expect to see an improvement in the ability to controllosses, as the casing always remains at the bottom of the well-bore5. This also allows every foot drilled to be cased off, bring-ing value through the elimination of nonproductive time(NPT) that can occur with the extended reaming and backreaming often needed in an open hole completion6.

DCwD technology was considered for drilling the direc-tional hole section needed to access the reservoir in M field, alarge Saudi Arabian development field. The 12¼” hole re-quired of the M field wells is a long directional section that ex-tends an average of 5,000 ft with a dogleg severity rangingfrom 2.5°/100 ft to 3.0°/100 ft. Moreover, this 12¼” intervalis drilled across a sort of problematic formation, includingfractured limestones, unstable shales and interbedded abrasivesands and siltstones.

Some of the potential hole problems that are expected in awell drilled in this field, based on information from offsetwells, are:

• Wellbore instability in shallower horizons as aconsequence of water flow, loss of circulation and/orextended reaming and back reaming across suchformations.

• Severe or total losses.

• Severe drilling dynamic effects due to the harsh drillingenvironment, such as “stick and slip” and highabrasiveness.

To access the reservoir in a large Saudi Arabian developmentfield, the operator is required to drill an intermediate 5,000 ftto 6,000 ft directional hole section with a dogleg severity vary-ing from 2.5°/100 ft to 3°/100 ft. The 12¼” borehole typicallycrosses several interbedded formations of limestone, shale andsand. This is associated with a variety of hole problems, whichhave occurred repeatedly in the offset wells. The main objec-tive for the operator was to mitigate the problems by findingalternative drilling technologies. Among those considered,Saudi Aramco determined that the recent developments in di-rectional casing while drilling (DCwD) technology may wellprovide an effective method for diminishing the associatednonproductive time (NPT).

The drilling engineering team conducted an extensive evalu-ation of the problems across this section, including issues withwellbore stability, water flow and loss of circulation; tighthole/stuck pipe incidents; and severe bit/stabilizer wear whiledrilling abrasive sands. After a promising technical and engi-neering evaluation of DCwD, followed by a detailed risk as-sessment striving to determine the potential of the application,a well was planned and executed using the DCwD service.

This article outlines the process carried out during all stagesfrom planning through the final deployment of the first 9⅝”DCwD application in Saudi Arabia. It shows how the technol-ogy was successful in reducing the impact of some of the prob-lems previously experienced while drilling the same section inother wells in the field. The information provided will serve asa starting point for the design and construction of subsequentwells, leading to further improvement in drilling performance.Best practices and lessons learned from this implementationare expected to become a model, with the know-how trans-ferred to other areas where comparable drilling problems occur.

As the technological benefits have been recognized by theoperator, this application has reestablished DCwD as a viabletechnology to address a number of challenges common inmany of the Saudi Arabian oil and gas fields.

INTRODUCTION

Casing drilling replaces conventional drillpipe and other

Directional Casing while Drilling (DCwD)Reestablished as Viable Technology inSaudi Arabia

Authors: Germán A. Muñoz, Bader N. Al-Dhafeeri, Hatem M. Al-Saggaf, Hossam Shaaban, Delimar C. Herrera,Ahmed Osman and Locus Otaremwa



• Possible tight hole, stuck pipe, shale sloughing andinvasive water flow.

• Early and deep bit and stabilizer wear while drillingacross the abrasive sands, along with a very low rate ofpenetration (ROP).

Saudi Aramco set the objectives for the well in this study as:

• Reevaluate the viability of using DCwD with 9⅝”casing in the M field.

• Drill the 12¼” section with casing and reach theplanned casing point with the minimum number ofBHA runs.

• Accomplish the directional plan for the section.

• Minimize the risks associated with typical hole issuesseen in offset wells (tight hole, stuck pipe and shalesloughing).

PLANNING

Extensive pre-job planning was performed to determine thefeasibility of using DCwD in the section and whether the ob-jectives were achievable or not. The main factors analyzedwere: torque and drag, casing connection selection, fatigue lifeon the casing, bit and underreamer (UR) hydraulics, and shockand vibration mitigation. The engineering modeling data andtheir comparison with the actual results — including lessonslearned — are discussed in this article.

The results of the feasibility studies were analyzed by bothengineering and drilling operations teams, and additional ef-forts were made to optimize the initial proposed BHA follow-ing several risk assessment sessions. The participation of rigcrew and third parties in these technical meetings — including,but not limited to, well supervisors, mud and cementing engi-neers, directional drillers, etc. — was crucial to review the de-sign basis for the job.

The 2,000 horsepower (HP) drilling rig selected to run thisapplication did not require any modification. The DCwD sup-plier performed a rig survey before the job and provided a cas-ing running tool, which was installed on the rig’s top drive, tomake up the casing connections and also transmit the requiredaxial and torsional loads while drilling.

A total of three downhole tool sets were made available forthis job. The directional BHA was planned to be retrieved andrun in hole again using drillpipe conveyed tools. Figure 1 illus-trates the typical kit of downhole tools, running tools and con-sumables required for a DCwD application.

TORQUE AND FATIQUE ANALYSES WITH CASINGCONNECTION SELECTION

The torque and drag modeling analysis done during the planning


stage took into account the proposed directional trajectory,typical friction factors (open hole and cased hole, as previouslycalibrated from similar wells), bit torque and tortuosity. Theresulting estimate of the string torque required to drill to totaldepth was close to 28,600 lbf-ft, Fig. 2a, which meant that thecasing connections had to be made up to 35,000 lbf-ft — 20%above the calculated drilling torque — to meet the criteria tosafely drill with the casing string.

Therefore, it was realized that a buttress connection — us-ing American Petroleum Institute (API) buttress thread casing(BTC) — was best suited for the job. But the field standardizedthread is a long thread casing, needed if it becomes imperativeto cut and re-thread the pipe, which meant the connectionalone could not handle the calculated torque with the requiredsafety factor of 35,000 lbf-ft. Therefore, multi-lobe torque(MLT) rings were recommended to increase the maximumdrilling torque capacity of the connections to 44,426 lbf-ft. TheMLT rings provide a positive makeup shoulder for the pin ends,which increases the API BTC connection torque capacity, Fig. 2b.

In addition to torque capability, the fatigue life of the BTCconnections determines whether they can be safely used for agiven DCwD application. The fatigue life analysis for the BTCcasing string was done using conservative drilling parameters— weight on bit (WOB), surface revolutions per minute (rpm)and ROP.

A fatigue failure occurs when the casing string is exposed tohigh alternating stress. The two common sources of alternat-ing/cyclical tensile stress are the bending stresses resulting fromrotating the casing in a directional section and vibration.

The maximum allowable stress for a DCwD application de-pends on the number of alternating stress cycles. In this partic-ular case, the maximum calculated stress level for 9⅝” casing— based on the directional plan — was less than 8,000 psi.That translates to a fatigue life for the casing of more than 10million cycles, Figs. 3 and 4, which represents less than 1% ofthe fatigue life of the string.

DIRECTIONAL BHA DESIGN

The BHA inside the 9⅝” casing was composed of 6¾” tools.The BHA extruding below the casing shoe consisted of a

Fig. 1. Standard DCwD equipment and consumables package.


started, another feature that has shown to have great impor-tance in such an application. Finally, the UR was dressed with12¼” arms to allow enlarging the hole to 12¼” without jeop-ardizing the ability of the BHA to pass through the 9⅝” cas-ing, Fig. 5.

SHOCKS AND VIBRATION MODELING

The dynamics of the proposed drilling system were modeled totest the stability of the whole DCwD BHA and determine theoptimum parameters for drilling through the different formations.

The bit for a DCwD application is typically selected after

directional drive system, a measurement while drilling (MWD)tool and an underreamer. The drive system was a point-the-bitrotary steerable system (RSS) along with an 8½” polycrys-talline diamond compact (PDC) bit that was driven by a mudmotor placed and locked inside the casing. This drive systemwas selected based on its proven performance in the field. TheMWD tool had the “pumps off” surveying feature that allowedit to take surveys when pumps are stopped. Ensuring that thetool is stationary when surveys are taken is a critical feature toensure good surveys in DCwD applications. This MWD toolwas also configured with a delayed surveying feature to minimizethe effect of lost surveys or signal noise when pumps are


Fig. 3. Plots showing accumulated fatigue life (left) and equivalent alternating stress (right).

Fig. 2. (a) Torque modeling for the “M” well; and (b) Torque capacity of MLT ring installed on a BTC connection.


reviewing the best performing bits from offset wells, includingnumber of blades, PDC cutter size, etc. The candidate bitswent through an integrated drill bit design platform analysis tocheck if they could drill the given formations and if they werecompatible with the UR cutting structure in the BHA. TheUR/bit cutting structures need to be compatible to enhance theresponse of the directional BHA. The bit selection process ledto the suggestion to start with a five blade bit for the softer topinterval of the section and then to move to a six blade bit

while drilling the more abrasive deep interval. The finite ele-ment analysis (FEA) software modeling also suggested, for op-timum cutting structure performance, that the ratio of weighton reamer to WOB must be maintained at 30%, Fig. 6.

The FEA software is a time-based 4D modeling tool used toaccurately predict a drilling system’s behavior using labora-tory-derived drilling mechanics data and physical input datathat characterizes the bit, BHA, wellbore, formations and op-erating parameters. FEA calculates solutions for a complexsystem by breaking down each component into small elements,establishing both stress equilibrium and strain compatibility ateach node of all the elements, and creating an assemblage ofthe individual equations, which is used to derive global solu-tions for the entire drilling system.

Using FEA, the drilling performance of the DCwD equip-ment and BHA was simulated for all the expected formationsunder different surface drilling parameter combinations —WOB and rpm — to determine the optimum and most stableparameter operating window. Figure 7 shows one example ofthe parameter road maps produced by the analysis: The green


Fig. 4. Typical SN curve used for fatigue life estimation.

Fig. 5. Directional BHA configuration.

Fig. 6. Weight on reamer to WOB ratio.

Fig. 7. Example of drilling parameter sensitivity plot done with FEA software.


zone shows the combination of drilling parameters where theBHA would be stable or without vibrations.

WELL CONTROL

Well integrity is one of the key aspects to be considered whendrilling sections, even for intervals where the associated risksare low, e.g., where there are no bearing pay zone formationsor hydrocarbon production. The DCwD response is not signif-icantly different from the regular approach when conventionaldrilling is used7, but it does require additional equipment fortripping out and in with a specific set of running tools, such as

to retrieve or set a new BHA. Under this circumstance — withcasing string on slips and with the drillpipe inside with runningtools — there are two different flow paths along which thewell can take an influx: (1) open hole casing annulus, and (2)casing string drillpipe annulus.

The service provider offered the latest generation of a sur-face well control tool, the casing circulating tool (CCT), whichis designed to provide a reliable means of well control whenthe drillpipe is being used to convey a retrievable DCwD BHA,Fig. 8. It also allows pressure testing before and after installa-tion, plus periodic circulation, reciprocation and rotation ofthe casing string to mitigate the chance of the casings getting


Fig. 8. BHA being retrieved with drillpipe conveyed tools and a false rotary table (right). The yellow and red boxes show the CCT components (bottom).


stuck as a result of sitting idle during the tripping process. Thiscan be done at any time and as frequently as required, depend-ing on the magnitude of the risks associated with the opera-tions. The tool has the following functionalities:

• Isolates the annulus inner string casing to containmaximum anticipated surface pressure.

• Simultaneously suspends the casing string, the innerstring and the BHA.

• Allows measurement of the surface pressure in the innerstring casing annulus.

• Makes up to the inner string casing in an expeditiousmanner.

• Has a secondary purpose once installed, enabling theoperator to reciprocate and circulate as needed toensure the casing string is free when differential stickinghas been identified as a potential risk, e.g., when drillingthrough depleted and porous formations.

The CCT is mounted below the top drive, and once at-tached, it becomes part of the primary load path. All parts ofthe CCT that are in the primary load path are designed for a500 ton load, according to API 8C requirements. The landing sub should be made up to the top of the casing

string and hung off in the split bushing on the rig floor. Thelanding sub has a modified buttress box thread connection,which allows the CCT, once it is made up to the drillpipestring, to be stabbed into the landing sub. This reduces theamount of time required to engage the CCT. As this threadmay be damaged during tripping, a thread protector is pro-vided to protect the thread during tripping operations. A spi-der or drillpipe slip bowl is placed on top of the split flange tosupport the drillpipe string when the pipe connections are be-ing made or broken.The CCT was developed to also provide well control when

the drillpipe is used for retrieving a BHA. The CCT includes achevron seal stack that provides a seal between the internal di-ameter of the casing and the drillpipe’s outer diameter once theCCT is stabbed into the landing sub. When the seal is insidethe landing sub, the casing/drillpipe annulus will be closed andcirculated conventionally through the drillpipe and the topdrive. The CCT may include a diverter sub with metered portsto allow circulation down the annulus between the casing anddrillpipe.

HYDRAULICS

The hydraulic program was planned around maintaining anequivalent circulating density (ECD) below the expected fracturegradient while achieving adequate hole cleaning.The hydraulic analysis was critical to balance the ECD cre-

ated in the small annulus between the casing and the borehole

and still have enough flow rate to clean the hole, while alsogenerating the required torsional loads from the mud motorand keeping a good hydraulic energy for the bit — HP persquare inch ≥ 1.5 hydraulic HP.Simulations showed that using an oil-based mud (OBM)

with a density of 72 pcf (9.6 ppg) at a flow rate of 500 gpmwill give annular velocities high enough — casing/open holeannular velocity was 235 ft/min with 550 gpm, Table 1 — toclean the hole, while maintaining an acceptable ECD below 79pcf (10.6 ppg), Fig. 9.

PREPARATION AND LOGISTICS

A certain amount of equipment preparation was done in the


Bit and UR Hydraulics

Bit UR

Flow Rate 550 gpm 0.00 gpm

Flow Area 0.90 in2 0.00 in2

Pressure Drop 271 psi 0 psi

Jet Velocity 195.65 ft/sec 0.00 ft/sec

Hydraulic Power 1.5 HHP 0.0 HHP

Impact Force 533 lb 0 lb

Annular Hydraulics

Ft/min Re Flow Regime

BHA/Open Hole 125.05 638 Lam

Drill Casing 1/Open Hole 234.78 1,059 Lam

Drill Casing 1/Liner 219.24 989 Lam

Drill Casing 1/Casing

Drill Casing 2/Casing

Hydraulic Lift 45.44 × 1,000 lb

Bottoms Up Time 45 min.

T

Table 1. Hydraulics modeling results: bit and UR hydraulics (top) and annularhydraulics (bottom)

Fig. 9. ECD with and without cuttings.


provider’s warehouse prior to sending the tools out to the rig.A special cut-to-length shoe joint was made to accommodatethe drill lock assembly (DLA), internal tandem stabilizers andmotor, which were to be installed before shipping. The DLAwas made up to the internal tandem stabilizers, which pre-vented excessive vibration at the DLA/casing profile nipple(CPN) connection. The motor was made up to the stabilizers,and the casing shoe joint was cut to such a length that the mo-tor’s rotor sub was the only part that extended past the reamershoe. A sleeve stabilizer that matched the drift of the casingwas installed on the motor so that it would be located just in-side the casing shoe. This location is critical in mitigating vi-brations between the motor inside the casing and the UR justbelow the casing shoe. This assembly was loaded into the cas-ing shoe joint and locked in place to the CPN with the DLA. Itwas then sent to the rig pre-assembled to save rig time. Figure10 shows details of the DLA and CPN configuration.

DRILLING OPERATION

The 13⅜” casing shoe and an additional 151 ft of new forma-tion were drilled out conventionally before DCwD operationsstarted to ensure that the UR would be positioned in the 12¼”open hole when the pumps were brought on to commencedrilling.

The 9⅝” casing was inspected, measured and gauged to ver-ify internal drift and joint length. A casing tally was preparedreferencing three key depths: (1) bit depth, which can changewith different BHAs; (2) total UR depth, which also changeswith the BHA; and (3) casing shoe depth, which is needed tocontrol the DCwD operations.

The lower components of the directional BHA were made upconventionally and secured in the rotary table. These includedthe 8½” PDC bit, RSS, MWD tool, roller reamer and 12¼”UR. The casing running tool was then rigged up to the topdrive, and the pre-assembled section was picked up. The motorwas made up to the directional assembly using the rig tongsand the casing joint, with the BHA hung off beneath it in theslips. The casing was then run using conventional casing running

procedures until the UR was below the 13⅜” casing shoe. One of the major advantages of the DCwD system is the

ability to retrieve the BHA at any point without the need topull the casing out of the hole. This allows the BHA to be re-trieved for any reason before reaching the end of the section,after which a new BHA can then be run in hole.

The tool used to retrieve the BHA is run into the hole usingdrillpipe. A false rotary table is required at the surface to runthe drillpipe through the casing. The retrieval tool is a grapple-type tool, which locks into the DLA latch sub and whenpicked up releases the locking mechanism and simultaneouslyopens a bypass port through the seal cups in the DLA to pre-vent swabbing on retrieval.

To latch the new BHA to the casing, the DLA is set into theCPN, using a hydraulic setting tool. After the hydraulic settingtool sets the DLA, it is hydraulically released, and the con-veyed drillpipe string with the hydraulic setting tool is thentripped out of the hole and the DCwD operations are resumed.

The procedure of retrieving and latching the BHA was per-formed three times during the drilled interval with no prob-lems.

The 12¼” interval was drilled in three runs as follows:

• Run 1: Drilled a total of 2,771 ft with an average ROPof 49 ft/hr (5 to 10 Klb WOB, 40 surface rpm and 550gpm flow rate).

The BHA was pulled out of the hole due to a motor failure.After changing the motor and while trying to run the newBHA, the operator observed an obstruction inside the casing.Because the BHA was unable to pass it, a decision was madeto pull the BHA back and then pull the casing out to the depthof the obstruction. Once it was on the surface, a failed MLTring was found, Fig. 11. All the rings and casing connectionswere checked prior to running the casing back in the hole. Theroot cause of the torque ring failure was related to overtorque,thread height and/or thread forms issues or to wrong ringcolor selection. The bit dull grade was 1-1-WT-A-X-I-ER-DMF.

• Run 2: The mud motor and bit were replaced, anddrilling was continued to a total of 1,762 ft with an


Fig. 10. The BHA pre-assembled DLA and CPN section components.

Fig. 11. Failed MLT ring (left) found while running in the hole to retrieve BHA#1, with the new ring (right).


average ROP of 26.5 ft/hr (6 to 10 Klb WOB, 40surface rpm and 550 gpm). The BHA was tripped outdue to slow ROP. The UR arms were found to beseverely worn out, Fig. 12. The bit dull grade was 1-1-WT-A-X-I-NO/RR-BHA.

The UR was changed, and BHA #3 was run back and setinto the CPN with no problem.

• Run 3: Drilled only 214 ft in abrasive siltstone, then theBHA was tripped out due to a drop in ROP (from 25 to0 ft/hr). The bit and UR arms were checked on thesurface. The bit was still in good condition (1-1-WT-A-X-I-NO/RR-TD), but the UR arms were found to beseverely worn out after only drilling 214 ft.

The cause of the UR’s wearing out in the two runs was asso-ciated with the use of medium speed mud motors in an abra-sive formation, which caused the UR to rotate at speeds closeto its design limit — 220 rpm for soft and nonabrasive forma-tions. The motors used were 0.3 rev/gal, which means that

with a 550 gpm flow rate and 40 surface rpm, the UR was rotating at 205 rpm.

Another factor that may have caused the UR to quicklywear out in the third run was the need to ream down a signifi-cantly undergauged hole along an abrasive formation, therebyaccelerating the wearing process. At that point, the hole wasbeing reamed faster than drilled to minimize the chances of anunplanned sidetrack.

Table 2 shows the bit run summary.

Torque and Drag

The friction factors used throughout pre-planning to predictthe torque and drag were conservative: 0.20 cased hole and0.25 open hole. Those conservative values resulted in a highpredicted torque and therefore a high connection torque.

The maximum surface torque that was recorded in the firsttwo runs was 22,000 lb-ft. It was decided after Run #2 to re-visit the pre-job model and reduce the friction factors to get amore representative value. The new friction factors used were0.15 cased hole and 0.20 open hole. These values proved to bemore realistic, Fig. 13; therefore, the connection makeuptorque was reduced from 38,000 lb-ft to 32,000 lb-ft.

CEMENTING OPERATION

To achieve cementing success, a full understanding of thechanges in the cementing operation for a DCwD application incomparison to conventional drilling cementing operations wasnecessary, in addition to adhering to the general best practicesfor cementing.

At the time of this implementation, there was no available


Fig. 12. UR arms in closed position from Run #2 (left) and Run #3 (center). Thepicture on the right shows the arms in the open (activated) position.

Run #

Mud Motor Inside CSG (Yes/No)

RSS (Yes/No)

RSS Specs Mud Motor

Specs

WOB (Klb)

Torque (ft-lb) × 103

Flow Rate

(gpm)

Surface RPM

PDM (rev/gal)

Total RPM

Start Depth

Inc. Azi.

Final Depth

Inc.Azi.

Bit Bit Dull Grade

1 Yes Yes

Point the Bit RSS 7/8 Lobes, 5

stages, 300 to 600 gpm

5-20 7-15 550 30 0.3 1954,965 ft37.36*28.02*

7,736 ft61.33*28.23*

11-1-WT-A-X-I-

ER-DMF

2 Yes Yes

Point the Bit RSS

7/8 Lobes, 6.8 stages, 300 to 600

gpm

6-20 17-21 580 32 0.29 2007,736 ft61.33*28.23*

9,498 ft68.86*30.01*

2

1-1-WT-A-X-I-

NO/RR-BHA

3 Yes Yes

Point the Bit RSS

7/8 Lobes, 6.8 stages, 300 to 600

gpm

9-23 22-25 550 25 0.29 1859,498 ft68.86*30.01*

9,712 ft69.28*30.15*

2R

1-1-WT-A-X-I-NO/RR-TD

T Table 2. Run summary for the DCwD drilled interval


field-tested solution for a two-stage cementing tool to be usedalong with DCwD — which is the traditional method in SaudiArabia for cementing across known weak and fractured forma-tions with the potential of a loss of circulation. The operatortook this into consideration, analyzed the potential risks andmitigation plan, and relied on the fact that even in highly sen-sitive formations, the ability to smear drilled cuttings into thepores of the formation could result in a stronger wellbore thatmight make multistage cementing systems unnecessary.

The need for full bore casing access to run and pull out ofthe hole the BHAs implied that the conventional floatingequipment — float collars with displacement plugs — couldnot be used. The plug landing nipple (PLN) was not availableat the time of the implementation, which meant that the pumpdown displacement plug (PDDP), designed to be used alongwith the DCwD BHA retrievable system, also could not be used.

The standoff obtained from the number of centralizers thatwere crimped on the casing was a challenge insofar as achiev-ing complete mud displacement during cementing since thesection was deviated. Also, a long rat hole existed because of along stick out of the BHA, leading to slumping of the cementslurry during placement and after displacement that could leadto a wet shoe.

Given the limitations of the formation fracture gradient,lead and tail slurries were designed at 101 pcf and 118 pcf, respectively. Fluid loss and the rheological properties of theslurries were optimized to ensure no annulus bridging andminimize frictional pressures.

A sufficient amount of spacer was determined to take intoaccount the in-pipe contamination because of the lack of me-chanical separation, e.g., bottom plugs, at the fluid interfaces— the properties optimized for efficient mud removal purposes.

The well was circulated for several hours before the start ofthe single-stage cement job. The cement job was executed asplanned, leaving 300 ft of cement slurry inside the casing, andthe well was shut-in — via the closed master valve at the sur-face — throughout the wait on the cement with no operational

issues; the well was shut-in because of the lack of float equip-ment to prevent cement flow back into the casing after itsplacement in the annulus. Contaminated cement slurry reachedthe surface; however, no pure cement was seen. The level in theannulus was seen to drop while waiting on the cement by anestimated volume of 45 bbl.

When operations resumed, the cement was tagged inside thecasing as expected and the casing was pressure tested to 1,100psi. Hard cement was drilled out of the casing and down to 33ft below the casing shoe.

The operator’s main objectives of obtaining cement back tothe surface and achieving competent cement around the shoewere successfully obtained. Figure 14 shows the actual pres-sure and the simulated pump pressure.

LESSONS LEARNED

1. Conservative friction factors were used during the planning phase, e.g., 0.20 for cased hole and 0.25 for open hole, which resulted in a recommended makeup torque of 38,000ft-lb — maximum predicted drilling torque + 20%. The friction factors observed were closer to 0.15 in the cased hole and 0.20 in the open hole, which resulted in a revised recommended makeup torque of 32,000 ft-lb. This will fur-ther reduce the connection torque requirements for future jobs in this area.

2. The designed BHA with a RSS performed as expected, pro-viding a smooth well profile with minimal well tortuosity that could affect casing fatigue life, which should lower torque requirements for the surface equipment and casing connections.

3. To be able to drill the interval in a single run, the UR arms design needs to be improved, e.g., by using premium PDC cutters and/or by modifying the gauge protection and exposed cutting area. The DCwD supplier is currently developing a new generation of high ratio URs with the field proven concept of cutter blocks, which is expected to replace the existing design for hard rock or abrasive applications.


Fig. 13. Torque and drag comparison (actual vs. modeling).

Fig. 14. Actual vs. simulated pump pressure.


operation. The benefits from the smearing effect, typically seen when using DCwD, were not observed 100% as expected. It is possible that this is linked to the surface rota-tion restriction (40 rpm) imposed by the high speed on the motor.

4. This project has reestablished DCwD as a viable technologyto address a multitude of drilling challenges common in Saudi Arabia.

ACKNOWLEDGMENTS

The authors would like to thank the management of SaudiAramco and Schlumberger for their support and permission topublish this article. The authors also would like to thank thecrew members of the rig, the rig foremen and the Schlumbergerteam for their support in the achievement of the project goals.This article was presented at the SPE/IADC Middle East

Drilling Technology Conference and Exhibition, Abu Dhabi,UAE, January 26-28, 2016.

REFERENCES

1. Graves, K.S. and Herrera, D.C.: “Casing during Drillingwith Rotary Steerable Technology in the Stag Field —Offshore Australia,” SPE Drilling & Completion, Vol. 28,No. 4, December 2013, pp. 370-390.

2. Warren, T., Houtchens, B. and Madell, G.: “DirectionalDrilling with Casing,” SPE paper 79914, prepared forpresentation at the SPE/IADC Drilling Conference,Amsterdam, The Netherlands, February 19-21, 2003.

3. Karimi, M., Petrie, S.W., Moellendick, E. and Holt, C.: “AReview of Casing Drilling Advantages to Reduce LostCirculation, Augment Wellbore Strengthening, ImproveWellbore Stability, and Mitigate Drilling-InducedFormation Damage,” SPE paper 148564, presented at the

4. Proper planning and logistics are crucial to a successful DCwD operation. The following, in particular, need to be considered for DCwD applications:

• The PLN was not available, which meant that thePDDP could not be used. This affected the plannedrotation and reciprocation of the casing before andduring the entire cementing job, which is one of the keyadvantages of DCwD. In future applications, this wouldhelp break up the gelled stationary pockets of drillingfluid and loosen cuttings trapped in the gelled drillingfluid.

• Lost circulation pills could also be pumped ahead of theslurry to minimize losses.

• Foam cement is an option that could be considered tofurther lighten the cement column and reduce the risk oflosses.

• Using a low speed/high torque motor, e.g., 7:8 lobes, 3.3stages, is recommended to prevent premature wear ofthe UR caused by the high speed rotation.

• The casing running tool was provided with a 4½”internal flush (NC50) top connection, which preventedthe top drive from being used to make up the casing.This required the use of undersized power tongs at thestart of the operations and resulted in 4 hours of NPT.This could be eliminated by having a 6⅝” regular topconnection, which will improve operational efficiencyand reduce safety risks.

• Usage of an integral blade for the motors, instead ofthread lock, is a must for future jobs. This minimizesthe risks of losing the blade when there is vibrationwhile drilling.

5. The service provider needs to launch an investigation to determine the root cause of the MLT ring failure and avoid a further occurrence. If the failure is related to the wrong MLT ring selection, the installation process will need to incorporate a revision before running the casing joints in the well. Operators will also need to verify that the base of the triangle is reached while making up the connections.

CONCLUSIONS

1. The DCwD system was able to achieve the planned trajec-tory while minimizing the potential risks associated with wellbore instability observed in offset wells, Fig. 15.

2. The CCT proved to be very effective in allowing the casing to be circulated while the drilling assembly was being tripped in and out of the hole.

3. Approximately 1,785 barrels of OBM were lost during the


Fig. 15. The planned trajectory (red) vs. the actual directional trajectory plot (blue).


BIOGRAPHIES

Germán A. Muñoz is a Senior DrillingEngineer in Saudi Aramco’sExploration & Oil DrillingEngineering Department. He is anexperienced engineer with more than18 years in the oil industry, mainlyfocused in drilling optimization and

the deployment of drilling technology. Germán developedhis drilling career holding field and office positions inColombia, Venezuela, Ecuador, Mexico and the U.S.,working for different oil companies before joining SaudiAramco in 2008.

His exposure to numerous drilling environments and hisknowledge in areas such as extreme extended reachdrilling, managed pressure drilling and directional casingwhile drilling, among others, enabled Germán toaccomplish the planning, execution and delivery of thelongest well in Saudi Arabia (37,042 ft MD) as well asachieve three other world records. He has also succeeded inthe reestablishment of 95⁄8” directional casing while drillingin the Kingdom.

He has authored and coauthored various technicalpapers for the Society of Petroleum Engineers (SPE). Hehas also been recognized by the company several timesthrough the Drilling & Workover Recognition Program forhis significant contributions.

In 1996, Germán received his B.S. degree in PetroleumEngineering from Universidad de América, Bogotá,Colombia.

Bader N. Al-Dhafeeri joined SaudiAramco in 2005. His experienceincludes work on several fielddevelopment projects, such as SouthGhawar, Manifa and AFK. Bader isnow a Drilling Engineering Supervisor.

He received his B.S. degree inPetroleum Engineering from the University of Tulsa, Tulsa,OK, and his M.S. degree in Petroleum Engineering fromHeriot-Watt University, Edinburgh, U.K.

the deployment of drilling


Petroleum Engineering

SPE/IADC Middle East Drilling Technology Conferenceand Exhibition, Muscat, Oman, October 24-26, 2011.

4. Moellendick, E. and Karimi, M.: “How Casing DrillingImproves Wellbore Stability,” AADE paper 11-NTCE-64,prepared for presentation at the American Association ofDrilling Engineers National Technical Conference andExhibition, Houston, Texas, April 12-14, 2011.

5. Chima, J., Zhou, S., Al-Hajji, A., Okot, M., Sharif, Q.J.,Clark, D., et al.: “Casing Drilling Technology Application:Case Histories from Saudi Arabia,” SPE paper 160857,presented at the SPE Saudi Arabia Section TechnicalSymposium and Exhibition, al-Khobar, Saudi Arabia, April8-11, 2012.

6. Sanchez, F.J., Turki, M., Houqani, S., Al-Nabhani, Y.N.,Al-Hinai, D.M., Maimani, S., et al.: “Casing While Drilling(CwD): A New Approach Drilling Fiqa Shale in Oman. ASuccess Story,” SPE paper 136107, presented at the AbuDhabi International Petroleum Exhibition and Conference,Abu Dhabi, UAE, November 1-4, 2010.

7. Beaumont, E., De Crevoisier, L., Baquero, F., Sanguino, J.,Herrera, D.C. and Cordero, E.: “First RetrievableDirectional Casing-While-Drilling (DCWD) Application inPeruvian Fields Generates Time Reduction and ImprovesDrilling Performance Preventing Potential NonplannedDowntime,” SPE paper 139339, presented at the SPE LatinAmerican and Caribbean Petroleum EngineeringConference, Lima, Peru, December 1-3, 2010.


Hatem M. Al-Saggaf joined SaudiAramco’s Drilling Department in2002. He is now a DrillingEngineering General Supervisor for theManifa increment. Hatem’s experienceincludes work on several drillingprojects, such as the Qatif field

development and Khurais increment, and he was a teamleader for the Nuiyyem field development.

He received his B.S. degree in Applied MechanicalEngineering from King Fahd University of Petroleum andMinerals (KFUPM), Dhahran, Saudi Arabia.

Hossam Shaaban is currently workingas the Schlumberger Drilling ToolsGeo-Market Operations Manager forKuwait. He was previously assigned toSaudi Arabia from May 2010 to April2015, where he held multiplepositions, including as the Project

Manager for the Drilling & Measurements activities inManifa. During his 15-year career with Schlumberger,Hossam has also worked as a Sales and MarketingManager for Drilling Tools, where he was responsible forthe implementation of the Level 3 casing drilling at theManifa field.

Hossam received his B.S. degree in Engineering fromBenha University, Cairo, Egypt, in 1994.

Delimar C. Herrera is a Senior DrillingEngineer for Schlumberger in SaudiArabia. He has 14 years of experiencein drilling and completions. Startinghis career as a Field Engineer fordrilling contractor IndependenceDrilling Ltd. in Colombia, Delimar

then moved to the drilling department in Ecopetrol wherehe held various positions, including Well Site Supervisorand Drilling Engineer. From 2007 to 2012, Delimarworked for Tesco Corporation, and then went to workwith Schlumberger Oilfield Services in various drillingengineering and operations roles, specifically on thetechnical development of casing while drilling and linerdrilling technologies in Latin America, Southeast Asia,Australia and the Middle East.

He received his B.S. degree in Petroleum Engineeringfrom Universidad Industrial de Santander, Santander,Colombia.


Ahmed Osman is currently the DrillingEngineering Lead for SchlumbergerDrilling & Measurements in SaudiArabia, where he has been for 13years. He started his career working asa MWD/LWD Engineer in Venezuela,Egypt, Algeria and Jordan. Ahmed

then became a Directional Drilling Engineer in Egypt andSudan, using different drilling systems in various drillingapplications. He then went on to work and manage severaldifferent drilling engineering projects in Egypt, Sudan,Vietnam, Thailand and Myanmar for different bigoperators, such as BP, Shell, Eni and Petronas.

Ahmed has participated in a number of Society ofPetroleum Engineers (SPE) conferences, technologyseminars and drilling training courses during the course ofhis career.

He received his B.S. degree in Mechanical Engineeringfrom the American University in Cairo, Cairo, Egypt.

Ahmed has received several internal awards and alsohas several published papers on advanced drilling systemsin different applications.

Locus Otaremwa is a CementingEngineer with Schlumberger. His sixyears of experience with Schlumbergerhas been characterized by providingsolutions to clients for challenges inboth primary and remedial cementingof oil and gas wells. Locus is currently

the focal point for cementing in the casing while drillingapplications in the Saudi Arabia.

He received his B.S. degree in Civil Engineering fromthe University of Dar Es Salaam, Dar Es Salaam, Tanzania.

Manager for the Drilling

then moved to the drilling

then became Directional

the focal point for cementing

development and Khurais


ABSTRACTetc. Once the excessive solids from the mud are screened out inthe shale shaker, the cleaned mud can then be recirculated tofulfill a suite of functional tasks. While drilling through porousand permeable zones, however, there is a high possibility oflosing a huge volume of the fluid phase of the mud whiledrilling or making a trip.

To avoid fluid loss while drilling a borehole, loss control additives are incorporated in the drilling mud for sealing andblocking the borehole pores by creating a low permeable mudcake on the borehole wall. It is necessary to prevent excessiveloss of the mud fluids into the porous formation since thatmay lead to a dramatic change in mud properties, which thenleads to different mud-related drilling problems, including in-creased mud cost, deposition of excessively thick filter cakeson the borehole wall, a significant increase in torque and dragproblems, a dramatic rise of equivalent circulation density,surge and swabbing pressures, an increase in casing runningload, problems in primary cementing and differential stickingproblems in the presence of high permeable formations1. Thisexplains the importance of having a fluid loss additive as apart of the formulation of drilling and completion fluids.

A typical fluid loss additive should be able to control theloss of drilling and completion fluids into the surrounding for-mations within an acceptable range: less than 15 cc/30 minutesin standard American Petroleum Institute (API) fluid loss testconditions, i.e., at room temperature under 100 psi pressure.The formulation of the drilling mud is engineered to keep fluidloss close to zero or as far as possible below the API recom-mended value to: (1) maintain the drilling fluid consistency, (2)ensure near wellbore formation stability, and (3) prevent dam-age to the pay zone, etc. Different types of chemicals and poly-mers are used by the petroleum industry to design drillingmuds, with mud rheology, density, fluid loss control property,etc., appropriate to a given well2.

Another important consideration in fluid design is the mini-mization or elimination of any detrimental effect caused to thesurrounding environment, ecosystems, habitats, etc., by drillingfluids. Due to strict environmental regulations around theglobe, the oil and gas industries are reluctant to use chemicalsand polymers that can cause a short- and/or long-term envi-ronmental impact.

Nearly three-fourths of the earth is covered in water, and

The Kingdom of Saudi Arabia spends a significant amount ofmoney per year on importing various fluid additives fromoverseas countries to meet the demand of the oil and gas sec-tor. An analysis of the drilling fluid additive import cost of2012 indicates that a substantial amount of money was spenton importing fluid loss control additives only. This very com-mon mud additive is frequently needed for both water- and oil-based mud formulations to fulfill certain functional tasks whiledrilling or while making a connection or a trip. Therefore, itstotal or partial replacement will save a considerable amountper year. If we only replaced 10% of the imported fluid lossadditive, we would see a significant savings per year. This justi-fies the development of in-Kingdom fluid loss additives usinglocally available natural, industrial and/or agricultural rawmaterials.

Localization of the product development would be highlybeneficial to the Kingdom in terms of industrial growth, tech-nology ownership and creation of new job opportunities forthe local public. It would also make a major contribution tothe national economy by bringing about a major reduction inthe mud additives’ import budget.

This article describes the preliminary results of testing a lo-cally developed fluid loss additive made using an agriculturalwaste product. Experimental results indicate that the fluid lossadditive is equally applicable for clay-free freshwater-basedand for saltwater-based drilling muds. Therefore, they demon-strate the additive’s suitability for current and future explo-ration and exploitation of oil and gas resources.

INTRODUCTION

Drilling fluid plays a vital role during the course of drilling awell. The mud, either water- or oil-based, is circulated fromthe surface to the bottom of the hole and then brought back tothe surface. The primary objectives for circulating the drillingmud are hole cleaning while drilling, cuttings suspension dur-ing the non-circulation period, maintaining of borehole stabil-ity while drilling or making a trip, etc.

A drilling mud serves a variety of other functions, such asbit cooling, energy supply to the mud motor, shale stabilization,

Preliminary Test Results of an Eco-FriendlyFluid Loss Additive Based on an IndigenousRaw Material

Authors: Dr. Md Amanullah, Dr. Jothibasu Ramasamy and Mohammed K. Al-Arfaj



those areas offer significant prospects for hydrocarbon re-sources, in addition to other valuable marine resources3. Sub-sequently, there has been a progressive move of drillingactivities from onshore to highly sensitive offshore and deep-water environments. To preserve the marine life, research hasfocused on the development of a new generation of “green”chemicals and mud additives that are eco-friendly, nontoxicand readily biodegradable, thereby avoiding short- and long-term environmental impact in highly sensitive offshore anddeep-water environments. This is reflected in the increase in research activities by the industry centered on finding or devel-oping virtually nontoxic, readily biodegradable and environ-mentally benign green chemicals and polymers for use indesigning high performance drilling and completion fluids4.

Drilling fluids are alkaline and usually have a pH above 9,ideally ranging from 9 to 10.5. Excessive loss of alkaline mudfiltrate to the near wellbore formation can cause swelling anddispersion of clays in the formations, leading to borehole insta-bility problems. Excessive fluid loss can also cause severe for-mation damage while drilling the pay zone5 due to the fluid’salteration of the poro-perm characteristics, fluid saturationlimits, relative permeability profiles, etc., of the near wellborereservoir formation. Therefore, effective control of fluid losswhile drilling a borehole is very important, for both thedrilling and the production phases of oil and gas explorationand exploitation.

Fluid loss additives minimize loss by creating mud cake withfavorable mechanical characteristics. The thickness of the mudcake plays an important role in mitigating a suite of drillingand reservoir engineering problems. Muds producing soft,thick mud cakes increase the potential of differential stickingwhen drilling a high permeable zone, and therefore, are not de-sirable for geological formations with high poro-perm charac-teristics and differential sticking potential. Deposition of athick mud cake will reduce the ease of recovery of stuck pipe ifthe mud cake creates strong sticking bonds at the drillpipe andmud cake interface.

This type of mud cake will also create high torque and leadto drag problems while drilling deviated, horizontal or ex-tended reach wells, and therefore, are not desirable for drillingsuch wells. The formation of soft, thick mud cake in a horizon-tal well may also create an embedded cuttings bed at the lowside of the borehole, leading to poor hole cleaning and tighthole problems. The formation of an embedded cuttings bed inthe presence of a soft, sticky mud cake may further lead to me-chanical pipe sticking problems. Subsequently, development ofsuperior fluid loss additives with excellent physical and chemi-cal properties compared to conventional mud additives willsignificantly mitigate these problems.

This article describes the application of an eco-friendly fluidloss additive derived from an indigenous raw material. The additive is applicable for both clay-free freshwater- and salt-water-based drilling muds and is able to control the loss of thefluid while drilling a borehole without any detrimental impact


to the surrounding environment, ecosystem, habitats, etc. Thenewly derived fluid loss additive has a particle size of less than150 microns and is easily dispersible in an aqueous medium ata low to moderate shear rate. The processing steps of produc-ing the additive include removal of the external skin of the rawmaterial, washing of the material to remove any dirt and left-over skin, and thermal treatment to improve the material’sprocessability and ease the manufacturing of a fine powderwith particle sizes of less than 150 microns.

The suitability of the locally derived agri-based additive wasevaluated by formulating clay-free freshwater-based and salt-water-based drilling muds with the additive and then conduct-ing: (1) API tests at room temperature and 100 psi overbalancepressure, and (2) high-pressure/high temperature (HPHT) fluidloss tests at 212 °F and 500 psi overbalance pressure. Prelimi-nary test results indicate that the locally produced fluid lossadditive labeled “DSP” can significantly mitigate the fluid lossbehavior of clay-free systems. Initial results also demonstratethe suitability of the indigenous raw material for localizationof product development in the Kingdom within the oil and gasindustry.

INDIGENOUS RAW MATERIALS

Several agricultural waste materials available from various lo-cal sources were evaluated to select a suitable raw material forthis feasibility study. A cursory study of the performance of thelocally available product selected demonstrated its suitabilityas a fluid loss control additive for freshwater- and saltwater-based drilling muds. Preliminary evaluation of the volume ofthe source material readily on hand then indicated the avail-ability of hundreds of thousands of tons of this material peryear. Due to the renewable nature of this source material, itsavailability can be increased significantly to meet the changingdemand of the oil and gas industry. Subsequently, the selectedraw material was determined to be a viable local source ofsupply of the material needed to create the additive, leading tolocalization of product development for oil and gas field appli-cations. The advantages of localization of product develop-ment to replace the imported fluid additives, whether in wholeor in part, are: (1) reduction of the import cost, (2) increase inthe growth of the local industry, (3) creation of new job oppor-tunities for the public, and (4) contribution to the local andnational economy.

MATERIALS AND METHODS

Preparation of DSP

Figure 1 shows the process flow for the fluid loss additivepreparation. Initial treatment is to clean all the external dirtand skin from the raw material to isolate the base material,and then to wash that material with freshwater to remove anysticky material from the seed. The seed is then treated thermally


slowly to the fluid phase to provide adequate time for propermixing and homogenization of the system. The pH of the mudwas adjusted to 10 by adding an appropriate amount ofsodium hydroxide (NaOH) solution. In the case of excessivefoaming, 2 to 3 drops of defoamer were added to remove anyair bubbles. To keep the DSP suspended homogeneously in thefluid system, 1 g Xanthan gum (XC) polymer or 2 g PHP wasadded to the mud as a viscosifier to raise the viscous propertiesof the fluid before adding the DSP. Table 2 shows the formulation of freshwater- and saltwater-

based muds used in tests to evaluate the fluid loss behavior ofthe mud at API and HPHT conditions. A test temperature of212 °F and an overbalance pressure of 500 psi were used toevaluate the HPHT fluid loss behavior of the muds.

RESULTS AND DISCUSSION

API Fluid Loss Behavior

Figure 2 shows the API spurt loss behavior of several clay-freewater-based systems. Comparison of the spurt loss behavior ofthe clay-free system with XC polymer alone (Test-1) and withDSP added (Test-2) indicates 90 cc API spurt loss for the XCpolymer containing system but only 9 cc API spurt loss afteradding DSP to the clay-free system. This is about a 90% dropof API spurt loss due to the presence of DSP. This undoubtedly

to remove excessive moisture and make the seed more brittlefor easier grinding. Next, the seeds are cooled to room temper-ature. After cooling, the seeds are ground by placing them inthe sample placement chamber of a programmable grindingmachine. Finally, the ground powder is sieved to isolate parti-cles less than 150 microns, which are stored.

Formulations to Evaluate DSP Performance

Table 1 shows several clay-free water-based mud (WBM) sys-tems that were used in tests to evaluate the API fluid loss behavior of the DSP-based fluid loss additive and then to com-pare that behavior with the API fluid loss behavior of severalconventional fluid loss additives, such as modified starch (MS)and psyllium husk powder (PHP). The components shown inthe formulation were mixed adequately by using a high speedmixer to prepare the mud systems. The ingredients were added


Fig. 1. Diagram showing the process flow for the fluid loss additive preparation.

Mud Components Test-1 Test-2 Test-3 Test-4 Test-5 Test-6

Water (ml) 350 350 350 350 350 350

PHP (g) 0 0 0 0 2 2

XC (g) 1 1 0 1 0 0

MS (g) 0 0 6 0 0 0

DSP (g) 0 6 0 6 0 6

NaOH (ml) to raisepH to 10

to raise pH to 10

to raisepH to 10

to raisepH to 10

to raisepH to 10

to raisepH to 10

Defoamer (cc) as required as required as required as required as required as required

T

Table 1. Clay-free freshwater-based mud formulations used in tests of the DSP additive

Mud Components Test-5 Test-6 Test-7 Test-8

Freshwater (ml) 350 350 – –

Red Sea Seawater (ml) – – 350 350

PHP (g) 2 2 2 2

DSP (g) 0 6 0 6

NaOH (ml) to raise pH to 10

to raisepH to 10

to raise pH to 10

to raise pH to 10

Defoamer (cc) as required as required as required as required

T Table 2. Clay-free freshwater- and seawater-based mud formulations used in HPHT tests of the DSP additive


proves the application and suitability of DSP as a fluid loss ad-ditive or additive supplement for clay-free water-based drillingfluid systems.

Comparison of the spurt loss behavior of the same DSP con-taining clay-free system (Test-4) with a clay-free mud systemcontaining only MS (Test-3), which is a conventional fluid lossadditive, indicates much better performance for both, withabout 40% reduction in spurt loss for the fluid containing thenewly developed DSP-based fluid loss additive. It again sup-ports the application of the DSP as a fluid loss additive to con-trol the fluid loss behavior of WBMs.

Comparison of another clay-free system with PHP (Test-5)and with both PHP and DSP (Test-6) indicates 2 cc spurt lossfor the clay-free system in the absence of DSP and only 1 ccspurt loss, i.e., about 50% lower spurt loss, in the presence ofDSP. This again proves the suitability of DSP as a fluid loss additive for WBM systems.

Figure 3 shows the API fluid loss behavior of several clay-free water-based systems. Comparison of the API fluid loss behavior of the clay-free systems used in Test-1 and Test-2 in-dicates 175 cc API fluid loss for the XC polymer containingsystem but only 31 cc API fluid loss after adding DSP. This is

about an 82% drop of fluid loss due to the presence of DSP.This undoubtedly proves the application and suitability of DSPas a fluid loss additive or additive supplement for water-baseddrilling fluid systems.

Comparison of the fluid loss behavior of clay-free mud con-taining only MS (Test-3), which is a conventional fluid loss ad-ditive, with the earlier DSP containing clay-free system (Test-4)indicates better performance for the newly developed DSP-based fluid loss additive. It again supports the application ofthe DSP as a fluid loss additive to control the fluid loss behav-ior of clay-free WBMs.

Comparison of a clay-free system with PHP with and with-out the presence of DSP (Test-6 and Test-5, respectively) indi-cates a much higher fluid loss in the absence of DSP. It is about50% higher than the clay-free system containing the DSP as afluid loss additive supplement. This again proves the suitabilityof DSP as a fluid loss additive for WBM systems. The red lineshown in Fig. 3 indicates the API recommended maximumfluid loss value — which is less than 15 cc/30 minutes filtra-tion time — for water-based drilling fluid systems. The pres-ence of the DSP in the clay-free system in Test 6 reduced thefiltration behavior of the system to 25% below the API recom-mended value. The results again demonstrate the suitability ofthe DSP as a fluid loss additive or additive supplement forclay-free water-based drilling fluid systems.

Figure 4 shows the API mud cake quality and thickness ofseveral clay-free water-based systems. Comparison of the mudcake thickness of the clay-free systems used in Test-1 and Test-2 indicates the formation of very thin but poor quality mudcake for the XC polymer containing system and a thin, goodquality mud cake after adding DSP. The improved quality of theDSP containing mud cake is reflected in the significant drop inthe API spurt and fluid loss behavior of the DSP containingclay-free systems previously discussed. The deposition of thin,good quality mud cakes will play a positive role in reducingthe scope of differential sticking in a borehole environmentprone to that problem. It will also play a positive role in reduc-ing other mud cake related drilling problems. In conclusion, it


Fig. 2. Evaluation of the API spurt loss behavior of tested clay-free drilling fluids.

Fig. 3. Evaluation of the API fluid loss behavior of tested clay-free drilling fluids.

Fig. 4. Evaluation of the API mud cake thickness behavior of tested clay-freedrilling fluids.


can be said that the agri-waste-based product DSP has a highpotential for use as a locally available raw material for devel-opment of additives/products for oil and gas field applications.

HPHT Fluid Loss Behavior

Figure 5 shows the HPHT spurt loss behavior of several clay-free freshwater- and saltwater-based systems at 212 °F and 500psi overbalance pressure. Comparison of the spurt loss behav-ior of the clay-free freshwater-based muds used in Test-5 andTest-6 indicates 8.4 cc HPHT spurt loss in the absence of DSPbut only 4 cc HPHT spurt loss in the presence of DSP. This is adrop of more than 50% of HPHT spurt loss due to the pres-ence of DSP. In the case of the clay-free saltwater-based mudsused in Test-7 and Test-8, the results again show a reduction inspurt loss in the presence of DSP. All comparisons support theapplication of DSP as a fluid loss additive or additive supple-ment for both clay-free freshwater- and saltwater-baseddrilling mud systems.

Figure 6 shows the HPHT fluid loss behavior of severalclay-free freshwater- and saltwater-based systems at 212 °Fand 500 psi overbalance pressure. Comparison of the HPHTfluid loss behavior of the clay-free freshwater-based muds usedin Test-5 and Test-6 indicates 76.4 cc HPHT fluid loss in the

absence of DSP, but only a 30 cc HPHT fluid loss in the pres-ence of DSP. This is more than a 60% drop of HPHT fluid lossof the freshwater-based mud due to the presence of DSP. In thecase of the saltwater-based clay-free systems used in Test-7 andTest-8, the results again show a reduction in fluid loss in thepresence of DSP. This supports the application of DSP as afluid loss additive or additive supplement.

Figure 7 shows the HPHT mud cake thickness of clay-freefreshwater- and saltwater-based systems at 212 °F and 500 psioverbalance pressure. Comparison of the mud cake thicknessof these mud systems indicates the formation of very thin mudcakes in both the absence and the presence of the DSP. This in-dicates that the DSP has no unusual effects on the physical be-havior, i.e., thickness of the mud cakes; however, in subsequenttests, the muds containing no DSP produced poor quality mudcakes due to the lack of formation of a dispersed well andtough mud cake as revealed while conducting the filtration test.The superior quality of DSP containing mud cake was reflectedin the dispersed well formation and the homogeneous nature ofthe mud cakes. The deposition of thin, good quality mud cakescan play a positive role in reducing the scope of differentialsticking in borehole environments prone to that problem.

The API and HPHT fluid loss test results previously de-scribed support the application of DSP as a locally derivedfluid loss additive/product for oil and gas field applications.

CONCLUSIONS

In conclusion, the preliminary experiments have demonstratedthat locally available agri-waste DSP used as a fluid loss additiveis applicable for clay-free freshwater and saltwater systems inoil and gas field applications. Furthermore, due to the organicnature of the raw material and the use of an environmentallyfriendly, thermo-physical preparation method, the incorporationof the additive in fluid will have no detrimental impact on thesurrounding environment, ecosystems, habitats, etc.

This result will open up the potential of finding applicationsfor various natural, agricultural and other industrial products,byproducts and waste products in oil and gas field fluid design.


Fig. 5. Evaluation of the HPHT spurt loss of tested clay-free freshwater- andsaltwater-based muds.

Fig. 6. Evaluation of the HPHT fluid loss of tested clay-free freshwater- andsaltwater-based muds.

Fig. 7. Evaluation of the HPHT mud cake thickness of tested clay-free freshwater-and saltwater-based muds.


ACKNOWLEDGMENTS

The authors wish to thank the management of Saudi Aramcofor their support and permission to publish this article. Theauthors cordially acknowledge the financial support of EXPECARC management for this pioneering research. Our specialthanks to our chief technologist Nasser Khanferi for his en-couragement and support for this innovative research, and toOmar Fuwaires and Turkie Alsubaie for testing and evaluationof the product. We also would like to thank Al-Hasa ResearchCenter for supplying the date seed samples for this research.

This article was presented at the SPE Oil and Gas IndiaConference and Exhibition, Mumbai, India, November 24-26,2015.

REFERENCES

1. Alford, P., Anderson, D., Bishop, M., Goldwood, D.,Stouffer, C., Watson, E., et al.: “Novel Oil-based MudAdditive Decreases HPHT Fluid Loss and EnhancesStability,” paper AADE-14-FTCE-18, presented at theAADE Fluids Technical Conference and Exhibition,Houston, Texas, April 15-16, 2014.

2. Amanullah, M., Marsden, J.R. and Shaw, H.F.: “AnExperimental Study of the Swelling Behavior of Mudrocksin the Presence of Drilling Mud Systems,” CanadianJournal of Petroleum Technology, Vol. 36, No. 3, March1997, pp. 45-50.

3. Amanullah, M. and Yu, L.: “Environment Friendly FluidLoss Additives to Protect the Marine Environment from theDetrimental Effect of Mud Additives,” Journal ofPetroleum Science and Engineering, Vol. 48, Nos. 3-4,September 2005, pp. 199-208.

4. Amanullah, M., Al-Arfaj, M.K. and Al-Abdullatif, Z.A.:“Preliminary Test Results of Nano-based Drilling Fluids forOil and Gas Field Application,” SPE paper 139534,presented at the SPE/IADC Drilling Conference andExhibition, Amsterdam, The Netherlands, March 1-3,2011.

5. Amanullah, M.: “A Novel Method of Assessment of Spurtand Filtrate Related Formation Damage Potential ofDrilling and Drill-in Fluids,” SPE paper 80484, presentedat the SPE Asia Pacific Oil and Gas Conference andExhibition, Jakarta, Indonesia, April 15-17, 2003.


BIOGRAPHIES

Dr. Md. Amanullah is a PetroleumEngineering Consultant working atSaudi Aramco’s Exploration andPetroleum Engineering Center –Advanced Research Center (EXPECARC). Prior to joining Saudi Aramco,he worked as a Principal Research

Scientist at CSIRO in Australia. Aman is the lead inventor of a vegetable oil-based

dielectric fluid (patented) that led to the formation of aspinoff company in Australia for commercialization of theproduct.

He has published more than 70 technical papers andfiled 25 patents, with nine already granted. Two of Aman’spatents were highlighted in two scholarly editions of twobooks published in the U.S. He is one of the recipients ofthe 2005 Green Chemistry Challenge Award from theRoyal Australian Chemical Institute. Aman also receivedthe CSIRO Performance Cash Reward in 2006, the SaudiAramco Mentorship Award in 2008 and the World OilCertificate Award for nano-based drilling fluiddevelopment in 2009. He is a member of the Society ofPetroleum Engineers (SPE). Aman received the 2014 SPERegional Service Award for his contribution to theindustry.

He received his M.S. degree (First Class) in MechanicalEngineering from the Moscow Oil and Gas Institute,Moscow, Russia, and his Ph.D. degree in PetroleumEngineering from Imperial College, London, U.K.

Dr. Jothibasu Ramasamy is aPetroleum Scientist working with theDrilling Technology Team of SaudiAramco’s Exploration and PetroleumEngineering Center – AdvancedResearch Center (EXPEC ARC). Hejoined Saudi Aramco in July 2013.

Prior to this, he worked as a Research Fellow with theDepartment of Chemistry at the National University ofSingapore and as a Postdoctoral Fellow with the CatalysisCenter at the King Abdullah University of Science andTechnology (KAUST), Saudi Arabia.

Jothibasu received his B.S. degree in Chemistry fromBharathidasan University, Tiruchirappalli, India, and hisM.S. degree, also in Chemistry, from Anna University,Chennai, India. In 2010, he received his Ph.D. degree inChemistry from the National University of Singapore,Singapore.

Jothibasu has published 15 techincal papers and filedthree patents.

Scientist at CSIRO in

Prior to this, he worked


Mohammed K. Al-Arfaj joined SaudiAramco in 2006 as a PetroleumEngineer, working with the DrillingTechnology Team in the Explorationand Petroleum Engineering Center –Advanced Research Center (EXPECARC). He works in the area of drilling

and completion, and has conducted several projects in theareas of shale inhibition, drilling nano-fluids, losscirculation materials, spotting fluids, swellable packers,completion fluids and oil well cementing.Mohammed received his B.S. degree in Chemical

Engineering from King Fahd University of Petroleum andMinerals (KFUPM), Dhahran, Saudi Arabia, in 2006. In2009, he received his M.S. degree in Petroleum Engineeringfrom Heriot-Watt University, Edinburgh, Scotland.Mohammed is currently pursuing a Ph.D. degree inPetroleum Engineering from KFUPM.


nd completion, and


ABSTRACTcollapsed and parted, and when the well contains leaking tub-ing hanger seals that are not holding pressure. Because of theseconditions, meeting the requirement by some companies tohave dual-independent shutoff barriers for the tubing and tub-ing casing annulus is unlikely using conventional methods.With a kill fluid column pumped into the annulus, however,there is a tested, proven alternative method for a successful solution: a cryogenic freeze plug.

STATEMENT OF THEORY AND DEFINITIONS

Pipe freezing is a method of isolating the inside diameter of apipe or pipes for maintenance or repair. To accomplish this, ametal container, designed to contain liquid nitrogen and to fitaround the pipe to be frozen, is installed around the pipe. Thecontainer is then precooled with nitrogen gas and then filledwith liquid nitrogen to freeze the water-based fluid inside thepipe. The frozen ice becomes a pressure barrier. In cases of cement filled outer annuli, the outer barrier is already in place,yet the cold transfers through the cement and into the fluid ofthe inner strings of casing and tubing, causing the fluid to formthe freeze plug. Further cooling lengthens the ice mass, whichbecomes very stable and controllable. Temperature monitoringsensors allow consistent verification of both the temperaturesapplied to the surface of the pipe as well as the temperatures ofthe nitrogen source. A gradual decrease in temperature is facil-itated to a range of 0 °F to -80 °F to ensure adequate cooling hasbeen applied, enough to provide a pressure resistant ice plug.

This pipe freezing technique has been safely and successfullyused over many years for many types of repairs. Wellhead andtree replacements, casing valve replacements, and other drillingand production problems that require total well isolation havebeen performed using ice plugs as a primary or secondary bar-rier. The freezing of multiple strings of pipe is not outside thenormal operations, but instead is a preferred method of isola-tion because the freeze plugs can be pressure tested to verifyintegrity and can be maintained indefinitely until all repairs orreplacements have been made. Single string freezes, by allow-ing a break in the connection above the freeze, provide the opportunity to add a valve or other component without per-forming a costly fluid kill operation. Negative and/or positivepressure testing of the freeze plug’s integrity can confirm isolation.

The objective of this article is to discuss the successful applica-tion of a cryogenic freeze plug to fulfill the requirements ofhaving dual shutoffs available prior to removing the produc-tion tree. This operation is presented as a substitute to usewhen conventional means are not feasible.

The Saudi Aramco policy regarding the decompletion ofwells with downhole packers requires having two independentshutoff barriers in place — for the tubing and tubing casingannulus — prior to the removal of the production tree. Theseshutoffs must be independent and able to be simultaneouslyoperated. Moreover, each shutoff must be pressure tested sepa-rately. A dual shutoff is easily achievable with conventionalmeans, e.g., tubing plugs and tubing hanger back pressurevalves, or with a combination of the two.

This pioneering operation was proposed when, prior to removing the production tree from an oil producing well, theproduction tubing was found to have collapsed and parted.Given these conditions, the only annular barrier was the killfluid column. The well also had leaking tubing hanger sealsthat were not holding pressure. As a result, introducing an additional shutoff barrier would be challenging.

This need for a second shutoff application led to the proposalto utilize the method for creating a cryogenic freeze plug as a so-lution. When the kill fluid column, filling the tubing and tubingcasing annulus, was frozen using the cryogenic freeze plug meth-od, it allowed the fluid to mimic the form of a second barrier.

This temporary secondary barrier would withstand the re-quired pressure test if there were a full column of kill fluid inthe tubing and tubing casing annulus.

This article reviews the methodology, purpose, technique,and qualification of using cryogenic freezing to create a secondbarrier. It also supports the positive trend in technical reviewstoward new methods or alternative techniques for nonconven-tional isolation barriers or shutoffs.

INTRODUCTION

The removal of a production tree for the decompletion of anoil producing well with a downhole packer can be anythingbut routine, particularly when the production tubing has

Pioneering Utilization of Fluid Cryogenicsin Mimicking Shutoff Barrier Characteristics

Authors: Nawaf D. Al-Otaibi, Nelson O. Pinero, Ibrahim A. Al-Obaidi and Carlo Mazzella



DESCRIPTION AND APPLICATION OF EQUIPMENT AND PROCESSES

To assure that this service is safe and reliable, independenttests and research have been conducted to determine the effectsof subjecting API grades of tubing and casing to liquid nitro-gen temperatures.

A testing laboratory was retained to perform mechanicaltesting of several grades of API tubing and casing and to un-dertake a metallurgical examination to determine if they areaffected by cryogenic temperatures.

This involved tensile tests and tests of the Charpy impact onprepared samples from each of the four provided grades of APIpipe. One tensile sample from each was tested at ambient con-ditions to establish a base line of property values; another sample from the same pipe was then tested at temperaturesranging from -30 °F to -100 °F through the course of the test;and yet another tensile sample was tested at a constant temper-ature near -230 °F. Next, a Charpy set from each pipe wastested at the impact test temperature prescribed in the API5CT and 5D specifications, with another set tested at an im-pact temperature of -60 °F. All test temperatures were moni-tored, with thermocouples attached directly to the samplesduring the tensile tests performed at temperatures other thanambient. The Charpy tests were monitored with a thermo-couple placed directly in the test bath.

In addition, two sections of the tested N80 pipe were sub-mitted to another test laboratory for metallurgical assessmentof retained austenite. One sample was taken directly from thearea that received the cryogenic application during testing. Thesecond was taken from a section of pipe located well awayfrom the cryogenic exposure area. This examination using X-ray diffraction would show any effects the frequent cryogenicexposure may have had on the microstructure of the material.

Operational Procedures

Safety was the key criterion that drove the design execution ofthis job. Many factors were considered during job planning,which included:

• A detailed job safety plan covering each technical stepin the workover.

• Contingency planning in case of a well control event.

• Issues involving the release of hydrogen sulfide.

• Avoidance of leaks at the surface that would jeopardizethe integrity of the ice plug being formed.

As a part of the work scope, it was determined that severalconditions must be met to perform the freeze plug successfully:

• The casing-casing annulus must be cemented or full of awater-based fluid.

• The tubing casing annulus and tubing must be filledwith a water-based fluid.

As a part of the ongoing operation, the work scope condi-tions were met with 0 psi pressure readings on the tubing andtubing casing annulus.

The standard setup for a multi-string freeze is as follows:

• Excavate to a predetermined depth, exposing 8 ft to 10ft of surface casing, Fig. 1.

• Inspect the pipe to ensure there are no visible defects inthe pipe or welds.

• Bolt the vendor’s freeze jacket onto the casing, leavingat least 2 ft of room from the casing head weld.

• Connect the thermocouples, nitrogen supply hoses andvent pipes, Fig. 2.

The excavation is then closed to all personnel until after thefreeze is complete and a gas test has been performed to verifythat no nitrogen gas is present.

With setup complete, nitrogen is flowed through the jacketuntil a trained service provider has confirmed that a pressureresistant ice plug is in place, Fig. 3. Pressure testing shouldthen take place until it is confirmed that all annuli are plugged.Then the safe removal of the tree can be facilitated and theblowout preventers installed. A pressure test should be per-formed again to ensure that all bolted connections are tested.Planning should consider the time needed to perform the freezeand so ensure an adequate nitrogen supply for lengthy repairor replacement periods, including delays. A continuous supplyof nitrogen should be planned for as a contingency plan, giventhat pipe freezes have been held for as long as 10 days.

Fig. 1. Excavation to a predetermined depth exposing 8 ft to 10 ft of thesurface casing.



The freeze plug does not affect the exposed area of casingsor wellhead equipment integrity. As seen in Table 1, the overallresults of the testing for the API 5CT N80 pipe showed thatthe tensile strength values of the subzero samples were slightlyhigher than the ambient samples’ tensile strength values. Theelongation values varied when comparing the subzero samplesto the ambient samples, but remained within a 5% difference.Table 2 shows that the Charpy impact values were lower forthe subzero impacts of the API 5CT N80 pipe in comparisonto ambient and +32 °F impacts, as is expected of any material.All tensile, yield and elongation values showed that the cryo-genic exposures were not causing a deleterious effect on any ofthe materials tested.

Blind samples were provided to the testing facility to deter-mine if a section of the N80 pipe that had been exposed to apipe freeze more than 100 times could be differentiated from asample that had not been exposed to the freezing process. Nodifference could be noted. The tensile test values from the area ofthe N80 pipe that had been subjected to numerous and frequenttesting only showed a slightly higher tensile strength. Addi-tional samples of API 5CT P110, API 5D S135 and API 5CTL80 pipe were provided to facilitate additional tests, Tables 3through 8. Pull testing at ambient and cryogenic temperaturesshows an increase in tensile strength in all but the N80 samples.

Additional tests of carbon steel samples exposed to differentcryogenic temperatures were performed at the Texas A&MUniversity Microscopy and Imaging Center using a scanningelectron microscope (SEM). Images produced by the SEM ofthe surfaces of these samples at fracture initiation zonesshowed similar morphological characteristics. During the ob-servations of these samples by the SEM, an energy dispersivespectrometry detector produced similar plots of elements pres-ent in each sample1.

CONCLUSIONS

Pipe freezing is most frequently used when a previous opera-tion — wireline, coiled tubing, snubbing, cementing or frack-ing — has left a situation where isolation from the wellborecannot be completed because of a valve failure or restriction.Wellhead and casing valves become inoperable for a variety ofreasons and frequently need to be replaced. Performing a fluidkill operation is sometimes not feasible because of either logis-tics or cost. When tool damage, inoperable valves or some typeof obstruction in the master valves leads to valve failure, afreezing operation below the wellhead to isolate all the valvesabove the casing head is proposed.

In circumstances where operation companies’ policies re-quire two barriers, a combination of kill weight fluids, down-hole plugs and pipe freezes can be implemented. On gas wellswhere no fluid is present for the freeze operation, millable orretrievable plugs can be set with a water-based fluid above toprovide an adequate freeze medium in the pipe. Pressure test-ing to ensure plug integrity can be easily facilitated, and after

PRESENTATION OF DATA AND RESULTS

In this case, a freeze plug was placed through the tubing casingannulus and the tubing, covering a total height of approxi-mately 4 ft. To assist with heat withdrawal and ice formation,the hoses were prepared as previously shown in Fig. 2. Thelower hose served to withdraw heat from below and preventan ice plug from forming underneath, while the top hoseserved as the main ice forming hose.

Once all strings on the well had been frozen, the tubingcasing annulus was successfully pressure tested to 1,000 psiagainst the freeze plug, which allowed operators to nippledown the tree and nipple up the blowout preventer safely.

Fig. 2. Connection of the thermocouples, nitrogen supply hoses and vent pipes.

Fig. 3. Formation of the ice plug as nitrogen is flowed through the jacket.



Specimen Identifi cation

Reduced Area Dimensions (in.)

Area (sq. in.)

Yield Strength

0.2% (psi)

Yield Strength 0.5% EUL (psi)

Total Load (lb)

Tensile Strength (psi)

Elongation (%)

Ambient 0.755 x 0.235 0.177 94,940 95,185 19,360 109,115 25

Cryogenic 0.504 x 0.208 0.105 90,945 90,590 11,150 106,360 20

T

Table 1. Tensile test results for the API 5CT N80 pipe

Specimen Temperature Cryo. Area

Impact Value (ft-lbf)Lateral Expansion (Mils.) % Shear Fracture

Individual Avg.

1, 2, 3 +32 °F 66 70 74 70 61 76 77 100 100 100

1, 2, 3 +32 °F 74 68 67 70 77 74 75 100 100 100

1, 2, 3 −60 °F 58 61 58 59 59 62 78 100 100 100

T

Table 2. Charpy test results for the API 5CT N80 pipe



Area (sq. in.)

Yield Strength

0.2% (psi)


Total Load (lb)


Elongation (%)

Ambient 0.505 x 0.333 0.168 123,815 124,045 22,850 135,880 20.8

Cryogenic 0.502 x 0.331 0.166 137,350 142,805 24,840 149,490 20.8

T

Table 3. Tensile test results for the API 5CT P110 pipe



Individual Avg.

1, 2, 3 +32 °F 79 76 78 78 67 61 60 100 100 100

1, 2, 3 −60 °F 47 73 73 64 32 52 54 100 100 100

T

Table 4. Charpy impact test results for the API 5CT P110 pipe



Area (sq. in.)

Yield Strength

0.2% (psi)


Total Load (lb)


Elongation (%)

Ambient 0.503 x 0.418 0.210 154,040 157,685 36,710 174,600 13.9

Cryogenic 0.509 x 0.393 0.200 166,755 119,657 37,520 187,565 15.5

T Table 5. Tensile test results for the API 5D S135 pipe



Individual Avg.

1, 2, 3 Ambient 17 15 15 16 6 5 7 45 45 45

1, 2, 3 −60 °F 10 10 8 9 2 2 2 5 5 5

T

Table 6. Charpy impact test results for the API 5D S135 pipe



the repair or replacement, a post-repair or makeup pressuretest can also be performed to ensure that the new componentsare tested before drilling or production is resumed.

ACKNOWLEDGMENTS


This article was presented at the SPE/IADC Middle EastDrilling Technology Conference and Exhibition, Abu Dhabi,UAE, January 26-28, 2016.

REFERENCE

1. Pendleton, M.W. and Mazzella, C.: “Scanning ElectronMicroscopy Characterization of Carbon Steel Fractured byPressure while Exposed to Cryogenic Temperatures,”Microscopy and Microanalysis, Vol. 16, No. S2, July 2010,pp. 1260-1261.



Area (sq. in.)

Yield Strength

0.2% (psi)


Total Load (lb)


Elongation (%)

Ambient 0.755 x 0.211 0.159 91,920 92,185 16,640 104,455 24.0

Cryogenic 0.503 x 0.192 0.097 106,365 106,315 11,990 124,150 17.2

T

Table 7. Tensile test results for API 5CT L80 pipe



Individual Avg.

1, 2, 3 +32 °F 62 62 65 63 72 71 75 100 100 100

1, 2, 3 −60 °F 57 57 58 57 61 57 60 100 100 100

T Table 8. Charpy impact test results for the API 5CT L80 pipe



Carlo Mazzella is the Wild WellGlobal General Manager of SpecialServices. He has 32 years of experiencein the energy industry, with 29 years ofspecialization in hot tapping, cryogenicpipe freezing, and gate valve drilling. In addition to publishing numerous

cutting-edge industry papers, Carlo has coauthoredpioneering research in cryogenics hosted by the world-renowned Texas A&M University, College Station, TX. Heis a patent holder and master of freezing techniques whocontinues to expand industry knowledge, increasing theeffectiveness of intervention operations around the world.

BIOGRAPHIES

Nawaf D. Al-Otaibi joined SaudiAramco’s Drilling and WorkoverDepartment as a Drilling Engineer. Heworked in the operations side of thedepartment from 2010 to 2013.Afterwards, Nawaf joined theWorkover Engineering Department as

a Workover Engineer, where he worked on multiple criticalprojects.

He received his B.S. degree from King Fahd Universityof Petroleum and Minerals (KFUPM), Dhahran, SaudiArabia, in 2010.

Nelson O. Pinero began his career in1996 when he went to work forLagoven, a Venezuelan oil company,as a Foreman. In 1997, he beganspecializing as a Drilling Engineer andthen began working as a Drilling &Workover Engineer. In 2003, Nelson

started working as a Workover Foreman in Servicios Ojedain the western part of Venezuela. Two years later, he wentto work for BP Venezuela as a Workover Foreman. Thefollowing year, BP relocated him to Bogota, Colombia, towork as a Workover Engineer. Nelson joined SaudiAramco’s Workover Department as a Workover Engineer in2007.

In 1995, he received his B.S. degree MechanicalEngineering from National Experimental PolytechnicUniversity, Barquisimeto, Venezuela.

Ibrahim A. Al-Obaidi is a DivisionHead at Saudi Aramco’s WorkoverEngineering Department. During hiscareer, he has gained experience indrilling and workover engineering,drilling and workover operation andproduction engineering. Ibrahim has

been heavily involved in several upstream projects, also hehas been a member of numerous teams during his career.

He is a member of the Society of Petroleum Engineering(SPE).

In 1995, Ibrahim received his B.S. degree in PetroleumEngineering from King Saud University, Riyadh, SaudiArabia.

a Workover Workover W Engineer

been heavily involved

cutting-edge industry

started working as a



ABSTRACTThe reservoir is under secondary recovery using waterflood-

ing, mainly seawater. The seawater is injected at the peripheryof the field for reservoir pressure maintenance.

GEOLOGICAL SETTING

The oil from this major field is produced from a carbonatereservoir that is a composite anticline. The anticline is rela-tively asymmetric. Generally, the reservoir is characterized byheterogeneity in reservoir rock properties, salinity and fluidmovement. Major and minor faults identified from 3D seismicdata and associated fracture swarms have been observed tovarious degrees throughout the reservoir. The fluid mechanismin this specific area is highly influenced by the presence of frac-ture corridors and strata from super permeability1-3.

EFFECTS OF EXCESSIVE WATER PRODUCTION

As previously mentioned, seawater is injected at the peripheryof the field. The primary objective is to maintain a healthyreservoir pressure to keep oil wells flowing and ensure good oilsweep. Injection water could break through to oil producersand consequently be produced in association with the oil. Waterproduction mechanisms vary due to many factors related togeological complexities, rock and fluid properties, and theproximity of oil producers to water injectors. Excessive waterproduction has to be controlled to minimize its negative impacton oil production. Effects of increased water production include:

• Reduced oil production rate.

• Reduced efficiency of oil recovery.

• Increased hydrostatic pressure in the well.

• Relative permeability effects in the formation.

• Downhole scale in the formation and tubulars.

• Surface water handling bottlenecks.

• Corrosion failures (subsurface and surface).

• Additional treatment costs.

• Reduced profits from increased operating and capitalcosts.

Water management practices are an integral part of effectivewell and reservoir management to avoid various water produc-tion problems, which present major challenges in the oil andgas industry. Many strategies have been used in the industry tocontrol water production, both in producer wells and in injec-tor wells. There are many water control methods available inthe industry, including mechanical and chemical methods;sometimes a combination of both methods is used.

With the advent of horizontal drilling technology, uniqueopportunities have been seized to enable efficient and effectivewater management via horizontal wells. More complex wellsof various types and shapes have been drilled and completed.The benefits of drilling these wells not only include a reductionin development and operating costs because of the lower num-ber of wells, but also improvement in the reservoir perform-ance and in the management of fluid movements. Thesecomplex wells are drilled with various objectives, which mayinclude, but are not limited to, increased production, enhancedreservoir characterization, improved sweep, maximized recov-ery and efficient reservoir management.

Water management practices implemented for effective wa-ter control and to sustain oil production in two different areasof a major field are presented in this article. One exemplifieswater management practices in a conventionally developedfield, and the second describes drilling conformance technol-ogy utilizing smart maximum reservoir contact (MRC) wells.

INTRODUCTION

The subject field consists of three main segments: area-I, area-II and area-III. Initial production from area-I started in 1996,followed by area-II in 2003, and finally area-III began produc-tion in 2006. These areas were developed over a span of abouttwo decades, which offers a unique opportunity for gaugingthe impact of various technologies. A separate gas-oil separa-tion plant (GOSP) serves each production area. All GOSPs areequipped with wet crude handling facilities to desalt the crudeoil and separate the produced water. The produced processedwater is then injected back into the flank of the same reservoir,usually below the original oil-water contact1.

Advancements in Well ConformanceTechnologies Used in a Major Field in SaudiArabia: Case Histories

Authors: Ahmed K. Al-Zain, Mohammed A. Al-Atwi, Ahmed A. Al-Jandal, Rami A. Al-Abdulmohsen and Hashem A. Al-Ghafli



• Earlier well abandonment.

KEY ASPECTS OF WELL CONFORMANCE

The key to successful well conformance is the production strat-egy, from project planning to production, with a focus on de-veloping an oil field to ensure sustainable oil production andmaximize oil recovery. Once the field is on production, the fo-cus is shifted to excellently managing the reservoir by acquir-ing well and reservoir data. The data collection requirementsare part of the field’s surveillance master plan. Well surveil-lance and data acquisition are vital processes to effectively andcontinuously communicate with the reservoir to fully under-stand the response of fluid movements and to make the neces-sary adjustments to production and injection plans on awell-by-well or region-by-region basis in the face of any unde-sirable anomalies. The production and injection plans that are in agreement

with reservoir responses are then deployed for field implemen-tation. Collaboration among stakeholders is very important toensure compliance with well production and injection rates.One of the useful checks and balance tools is to employ theconcept of well target rates for oil producers and water injec-tors. The target rate compliance is then cross-checked fre-quently and reported monthly to management. Next is a briefdiscussion of this exercise.

COMPLIANCE WITH WELL TARGET RATES

Oil Production Side

Every oil producer serving a GOSP area is assigned a targetrate and a production priority. The wells are listed with thehigher producing wells at the top, giving them higher priority.This list, called production priorities, reflects the reservoir andproduction management strategy. The wells with top produc-tion priorities are the first to be flowed to meet the oil targetrate of the GOSP area while limiting produced water. Wells atthe bottom of the list, and so beyond the GOSP target rate, areto be shut-in as standby wells or as alternatives to replace ashut-in high priority oil producer — one that, for instance, isclosed for well service jobs. Wells are rate tested frequently, or continuously in the case of

the intelligent field, to ensure compliance with assigned targetrates. The wells may be choked or relaxed, via a surface chokevalve installed on the well flow line, to meet the assigned targetrates. The objective of well restriction is to balance oil produc-tion with water injection, optimizing drawdown on each wellto sustain oil production and slow water encroachment. Table1 shows a typical monthly report for oil rate compliance in thesubject field.

Water Injection Side

Likewise, a water injection target rate is assigned to every in-jector. Injection well rates are measured continuously via on-line meters. Every well is equipped with a surface choke valveto allow adjusting water flow to the assigned target rate. Theinjection target for every well is set such that a predeterminedinflow performance rate is achieved for that well and area ofthe field. The objective is to balance the water injection withoil withdrawal while maintaining a healthy reservoir pressureand ensuring good oil sweep. Table 2 shows a typical monthlyreport for water rate compliance.

WATER MANAGEMENT PRACTICES

Excessive unwanted water production is one of the undesirableresponses of fluid movement in the reservoir and a major con-cern since it may lead to negative consequences, including re-serve and ultimate recovery loss. Therefore, every opportunityhas to be taken to enhance stringent water management strate-gies to maximize oil production, conserve reservoir energy, reduce operation costs and protect the environment. Watermanagement is an integrated process that involves both sub-surface and surface facilities, including separator retrofits, sys-tem debottlenecking, pump upgrading, piping enlargement anddisposal well additions4, 5.Water management practices implemented for effective wa-

ter control while at the same time sustaining oil production intwo different field areas are presented next. One exemplifieswater management practices in a conventionally developedfield, and the second describes drilling conformance technol-ogy utilizing smart maximum reservoir contact (MRC) wells.

A rea % Complying Wells

% Wells Over Target

% Wells Under Target

I 97 2 1

II 100 0 0

III 100 0 0

Total 99 1 0

T

Table 1. Oil rate compliance for a typical month

Area % Complying Wells

% Wells Over Target

% Wells Under Target

I 83 0 17

II 100 0 0

III 93 0 7

Total 91 0 9

T

Table 2. Water rate compliance for a typical month



existing vertical and horizontal wells. This technique has beensuccessful in recovering the remaining unswept oil in areaswith a thin remaining oil column while preserving the waterunderneath. Short radius horizontal recompletions like this arepreferred to conventional water shut-off jobs because short ra-dius horizontal wells produce at a lower drawdown pressure.A lower drawdown pressure minimizes water breakthroughand sustains oil production for a longer time compared to rig-less water shut-offs. In addition, short radius horizontals cost66% less than drilling new horizontal wells. In high risk areas,the well is usually completed with inflow control devices(ICDs) to evenly distribute production contributions along thepay zone, which improves the oil sweep and defers any prema-ture water enchroachment7, 10.

For instance, Well-B was drilled and completed as a hori-zontal open hole producer at the top of the reservoir in a ma-ture location. The well showed a rapid water cut increase andceased to flow at a water cut above 70%. Accordingly, thewell was sidetracked in a different direction in the top 10 ft ofthe pay zone. Because operators encountered complete loss circulation while drilling the horizontal section, the wall wasequipped with an ICD completion. Figure 2 shows the water

WELL CONFORMANCE IN A CONVENTIONAL FIELD:AREA-I

Initially, area-I was developed using mainly vertical wells.Most wells are generally completed open hole. The last casingor liner is set at the top of the reservoir, which is then drilled,penetrating all zones to some point below the base of the reser-voir. With the advent of horizontal drilling and for variousstrategic reasons, infill wells have been completed as horizon-tal producers throughout the field during the last two decades.As water encroaches into the wellbore, the water is monitoredand evaluated using different diagnostic tools. These tools in-clude rate tests, surface fluid samples, production logs, satura-tion logs, etc. The purpose of this diagnostic work is toidentify the type of water and its point of entry. If the water isidentified as unwanted water, a remedial action to shut off thewater is considered using different approaches, based on theseverity of water encroachment.

Rigless Water Shut-offs

One option is to use rigless methods, such as wireline, to runbridge plugs or coiled tubing (CT) for cement squeezing, whichinvolves plugging back perforations with cement or calciumcarbonate chips capped with cement. The wireline option isvery cheap. Through tubing bridge plugs deployed on an elec-tric wireline have proven to be very effective on vertical wellsand are used routinely to shut off unwanted produced waterthroughout the field. Depending on various factors related togeological complexity, rock properties and the shortness of theremaining oil columns, the treated well can last from a fewmonths to 18 months on production before it ceases to flow6, 7.

In the case of horizontal wells, more sophisticated methodsusing CT are used to shut off water production. The CT isused to deploy mechanical tools and chemical treatment fluids.These chemical and mechanical treatments on horizontal wellshave been used with limited success8, 9.

For example, Well-A is completed as a cased hole horizontalproducer at the top of the reservoir in a mature area. The wellbegan to exhibit high water cut and ceased to flow with a wa-ter cut above 60%. A water shut-off job, using a through-tub-ing inflatable plug, was performed to shut off the watered outperforations. The inflatable plug was deployed and set acrossthe 4½” liner using a CT. Figure 1 shows the water cut per-formance before and after the water shut-off. Afterward, thewell achieved its target oil rate of 1.5 thousand barrels per day(MBD) with a water cut of less than 20%. This performancehas been sustained for about 12 months.

Horizontal Recompletions

The second option is to sidetrack a watered out well and drillhorizontally in the top 10 ft of the pay zone to maintain maxi-mum distance from the water zone. This option is viable for

Fig. 1. Water cut performance for Well-A.

Fig. 2. Water cut performance for Well-B.



cut performance before and after the sidetrack for Well-B. Af-ter the sidetrack, the well produced 3 MBD of oil at less than20% water cut. The well has a sustained flow at its target ratewith a water cut of less than 20% for more than two years.

Figure 3 compares the number of historical rigless watershut-offs with that of horizontal sidetracks for area-I. Duringthe seven-year review period, the engineering tendency was toselect the sidetrack option more frequently than the riglessshut-offs; there were 68 horizontal sidetracks drilled as com-pared to 18 rigless water shut-offs for the period. The prefer-ence for horizontal sidetracks is to a large extent related to thearea’s geological complexity, rock properties and a thin re-maining oil column. The horizontal recompletions have beenfound to considerably prolong well oil production with limitedwater production. The performance of water cuts for Well-Aand Well-B demonstrates this fact.

Area-I Field Performance

Figure 4 shows the positive impact of stringent compliancewith well target rates and of implementation of water manage-ment practices in area-I. The oil production rate was main-tained at the desired target while keeping the water cut below20% for the seven years of review.

WELL CONFORMANCE IN A SMART MRC FIELD: AREA-III

Area-III posed a variety of challenges that ruled out a conven-tional field development. Geological complexity, characterizedby reservoir heterogeneity in rock properties and the presenceof fault and fracture systems, governs the fluid mechanism inthis part of the field. The degraded reservoir quality of area-IIIlimits the productivity of wells. Therefore, the area was devel-oped mainly with MRC wells and equipped with smart com-pletions having intelligent field capabilities. The driving force

for this type of field development has been intensively investi-gated in other literature. The bottom-line objective is to sus-tain oil production on a long-term basis while avoidingpremature water breakthrough1-3.

Description of Smart MRC Well Completion

A typical MRC well is a trilateral or quadrilateral well. Figure5 shows a schematic of a typical smart trilateral well. The wellis drilled as an 8½” mainbore and cased with a 7” liner, sethorizontally into the top of the producing interval. A 6⅛” hor-izontal open hole is then drilled as a mainbore extension — themotherbore, L0. Then two 6⅛” open hole horizontal side-tracks, L1 and L2, are drilled by opening windows in the 7”liner across the motherbore. After drilling, a smart completionis installed with smart completion assemblies, including azonal isolation packer and flow control valve across each lateral.Control lines are extended from each assembly to a surfacecontrol panel to operate the flow control valve. Each valve has11 choke positions, ranging from fully closed to the equivalentof the tubing flow area. The lateral flow can be restricted todifferent degrees using the remaining choke positions; the goal

Fig. 3. Historical rigless water shut-offs and horizontal sidetracks in area-I.

Fig. 4. Water cut trend showing the positive impact of well conformance practicesin area-1.

Fig. 5. Schematic of a typical MRC smart trilateral well.



is to produce the lateral at an optimum oil production rate andlimit water production. Generally, laterals are produced all to-gether, honoring the commingled production target specifiedfor that well.

Utilization of Smart Completion in Water Management

The production performance for a smart MRC well is moni-tored very closely. Once premature water production is ob-served, comprehensive rate tests are performed whilemanipulating the downhole choke valve for each lateral to de-termine the source of the unwanted water that risks oil pro-duction. In addition, rate tests of production from all lateralscommingled are carried out to decide on the final choke settingfor each lateral’s valve.

For example, Well-C was observed cutting water, and thewater cut increased gradually to 51% while L0, L1 and L2produced at downhole choke positions of 5, 6 and 7, respectively.Accordingly, intensive rate tests were carried out for every lateralby manipulating each one’s downhole flow control valve. Fig-ure 6 shows the inflow control valve (ICV) choke performanceand rate results for the mainbore. It is clear that the mainboreis cutting water at the low choke position of 3; the water cutsincrease from 6.8% at the first choke position to 38.6% at thethird choke position. L1 showed a similar performance to that ofL0. Unlike the other laterals, the ICV choke performance of L2was very promising, Fig. 7; the water cut trend remains almostflat below 19%, indicating no sensitivity to the choke position.

In addition to the individual testing of each lateral to deter-mine its rate performance, tests were performed on the pro-duction of all laterals commingled together to assess the wellperformance. Rate tests are performed for three or more chokeposition scenarios. Table 3 shows the results of the commin-gling rate tests for a typical smart MRC well, Well-C. The firstscenario, showing the optimum oil production of about 10MBD with the least water cut of 3.4%, was subsequently selected as the production rate target for that well.

Area-III Field Performance

Area-III was the first Saudi Aramco development project to bedeveloped exclusively using MRC wells with ICVs for flowcontrol. The value gained from using smart MRC wells is de-picted in Fig. 8. The required oil production rate was sustainedwhile keeping the water cut below 10% for the first seven

Fig. 6. ICV choke performance for the Well-C mainbore.

Fig. 7. ICV choke performance for L2 in Well-C.

Downhole Choke Position

Production Data

Scenarios L-0 L-1 L-2Oil Rate (MBD)

Water Cut (%)

1st 1 1 10 10.7 3.4

2nd 3 1 10 10.2 11.3

3rd 3 3 10 9.2 18.9

T Table 3. Rate results of tests run for three choke position scenarios with alllaterals commingled in Well-C, a typical smart MRC well

Fig. 8. Water cut trend in area-III showing the value of smart MRC wells.



years of production. The smart completion, employed whiledrilling conformance technology, proved to be necessary to en-sure production sustainability in the face of premature waterencroachment despite the geological complexity of the field.

CONCLUSIONS

Crude oil production sustainability, as demonstrated by this ar-ticle, is a direct result of strategies that ensure adherence topragmatic practices to facilitate conformance in response tovarious factors related to fluid movements in structurally com-plex reservoirs. The success of well conformance is attributedto the selection of techniques that fit in the right circum-stances. This selection accuracy would not materialize withoutwell surveillance and data acquisition programs to sustain theflow of data to practicing engineers — the decision makerswho, through continuous observation and learning, respondagilely to changes to comply with strategic objectives. Beloware the main lessons learned:

• The key to successful well conformance is the fielddevelopment strategy, extending from the initial stage tothe final stages of the project. A long-term perspectiveoffers opportunity for technology exploitation.

• The advent of horizontal drilling technology andgeosteering capability in near real time has shifted thereliance on conventional water shut-offs to horizontalrecompletions.

• Following the evolution of smart technologies, MRCsmart completions became necessary to ensureproduction sustainability in the face of premature waterencroachment in highly complex geological regions offaults and fracture systems.

• Whether it is a conventional or smart field, collab-oration among stakeholders is vital to manifest suchsuccessful accomplishments.

ACKNOWLEDGMENTS

The authors would like to thank the management of SaudiAramco for their support and permission to publish this arti-cle. The authors further acknowledge Saudi Aramco’s SouthernArea Production Engineering management and personnel fortheir support during the issuance of this article.

This article was presented at the SPE/IADC Middle EastDrilling Technology Conference and Exhibition, Abu Dhabi,UAE, January 26-28, 2016.

REFERENCES

1. Saleri, N.G., Al-Kaabi, A.O. and Muallem, A.S.: “HaradhIII: A Milestone for Smart Fields,” Journal of Petroleum

Technology, Vol. 58, No. 11, November 2006, pp. 28-32.

2. Mubarak, S.M., Pham, T.R., Shamrani, S.S. and Shafiq,M.: “Using Downhole Control Valves to Sustain OilProduction from the First Maximum Reservoir Contact,Multilateral and Smart Well in Ghawar Field: Case Study,”IPTC paper 11630, presented at the InternationalPetroleum Technology Conference, Dubai, UAE, December4-6, 2007.

3. Al-Afaleg, N.J., Pham, T.R., Al-Otaibi, U.F., Amos, S.W.and Sarda, S.: “Design and Deployment of MaximumReservoir Contact Wells with Smart Completions in theDevelopment of a Carbonate Reservoir,” SPE paper 93138,presented at the Asia Pacific Oil and Gas Conference andExhibition, Jakarta, Indonesia, April 5-7, 2005.

4. Hintemair, R.W.: “Production Water Management,” SPEpaper 38798, presented at the SPE Annual TechnicalConference and Exhibition, San Antonio, Texas, October5-8, 1997.

5. Al-Khawajah, M.A. and MacDonald, H.W.: “WaterShutoff Results in High Permeability Zones in SaudiArabia,” SPE paper 29823, presented at the Middle EastOil Show, Bahrain, March 11-14, 1995.

6. Mohammed, M.A., Al-Mubarak, M.A., Al-Mulhim, A.K.,Al-Mubarak, S.M. and Al-Safi, A.A.: “Overview of FieldResults Using TTBP as Effective Water Shut-off Treatmentin Open Hole Well Completions in Saudi Arabia,” SPEpaper 39616, presented at the SPE/DOE Improved OilRecovery Symposium, Tulsa, Oklahoma, April 19-22,1998.

7. Al-Jandal, A.A. and Farooqui, M.A.: “Use of Short RadiusHorizontal Recompletions to Recover Unswept Oil in aMaturing Giant Field,” SPE paper 68128, presented at theSPE Middle East Oil Show, Bahrain, March 17-20, 2001.

8. Al-Zain, A., Duarte, J., Haldar, S., Al-Driweesh, S.M., Al-Jandal, A., Shammeri, F., et al.: “Successful Utilization ofFiber Optic Telemetry Enabled Coiled Tubing for WaterShut-off on a Horizontal Oil Well in Ghawar Field,” SPEpaper 126063, presented at the SPE Saudi Arabia SectionTechnical Symposium and Exhibition, al-Khobar, SaudiArabia, May 9-11, 2009.

9. Sharma, H.K., Duarte, J., Eid, M., Turki, S. and Vielma,J.R.: “Lessons Learned from Water Shut-off of HorizontalWells Using Inflatable Packers and Water Shut-offChemicals in the Ghawar Field of Saudi Arabia,” IPTCpaper 16637, presented at the International PetroleumTechnology Conference, Beijing, China, March 26-28,2013.

10. Al-Mulhem, N.I., Sharma, H.K., Al-Zain, A.K., Al-Suwailem, S.S. and Al-Driweesh, S.M.: “A Smart Approach in Acid Stimulation Resulted in Successful Reviving of Horizontal Producers Equipped with ICD



Completions, Saudi Arabia: Case History,” SPE paper 127318, presented at the SPE International Symposium and Exhibition on Formation Damage Control, Lafayette,Louisiana, February 10-12, 2010.

BIOGRAPHIES

Ahmed K. Al-Zain currently works asa Production Engineering Consultantin Saudi Aramco’s Southern AreaProduction Engineering Department(SAPED). Having joined Saudi Aramcoin 1983, he now has over 30 years ofexperience, mainly in production

engineering as well as in reservoir and drilling engineering.Also during this time, Ahmed has made many substantialcontributions in relation to the upstream sector.

He has published several technical papers on variouspetroleum engineering topics, such as acid stimulation,scale inhibition, water compatibility, transient well testing,advanced coiled tubing applications, automated well dataacquisitions and new technology applications.

Ahmed has participated in many technical Society ofPetroleum Engineers (SPE) conferences, workshops andteams, noticeably leading the production engineeringefforts in the Saudi Aramco carbon dioxide enhanced oilrecovery demonstration project from the initial designphase to commissioning.

His interests covers a wide spectrum of petroleumengineering aspects, such as well treatments, stimulations,well conformance, well integrity, well/reservoir dataacquisition, produced water management, unconventionalcompletions, smart completions, intelligent fields,deployment of new technologies and coachingsubordinates.

In 1989, Ahmed received his B.S. degree in PetroleumEngineering from Tulsa University, Tulsa, OK.

Mohammed A. Al-Atwi is a GeneralSupervisor in the Southern AreaProduction Engineering Department(SAPED), where he is involved in gasproduction engineering, wellcompletion, and fracturing andstimulation activities.

Mohammed joined Saudi Aramco in June 2003 as a GasProduction Engineer. He has been involved in severalassignments and projects since then. Mohammed’s previousexperience includes working as a Gas Drilling Engineer anda Well Completion Foreman. He also has workingexperience in the oil production and reservoir management.

Mohammed has published several technical reports,studies and Society of Petroleum Engineer (SPE) papers.

He received his B.S. degree in Petroleum Engineeringfrom the University of Tulsa, Tulsa, OK, and an M.S.degree in Business Administration from University ofStrathclyde, Glasgow, U.K.

engineering as well as

Ahmed A. Al-Jandal joined SaudiAramco in 1986 as a PetroleumEngineer for the Southern Area OilOperations Department, managing oil,gas and water operations. He joinedthe in-house Production EngineeringSpecialist program in 2001 and

graduated in 2005 as a Production Optimization Specialist.During this period of time, Ahmed also taught as aninstructor for the in-house Production Engineering School,covering well integrity, well rate testing and wellmonitoring subjects. Since 2007, he has been theSupervisor for one of the specialized units under theSouthern Area Production Engineering Department,covering the areas of acid stimulation and water injectionfor Ghawar field. In 2013, Ahmed was promoted to aPetroleum Engineering Consultant for his department.

He has authored/coauthored numerous Society ofPetroleum Engineer (SPE) papers and participated inseveral national and international conferences around theworld.

In 1986, Ahmed received his B.S. degree in PetroleumEngineering from King Fahd University of Petroleum andMinerals (KFUPM), Dhahran, Saudi Arabia.

Rami A. Al-Abdulmohsen joined SaudiAramco in 2001. Currently, he isworking as a Production Engineerhandling oil production in theSouthern Area of Ghawar reservoir.

Rami received his B.S. degree inComputer Engineering and his M.S.

degree in Petroleum Engineering, both from King FahdUniversity of Petroleum and Minerals (KFUPM), Dhahran,Saudi Arabia.

Hashem A. Al-Ghafli is a ProductionEngineer with more than 6 years ofexperience in the oil and gas industry.As a Production Engineer (havingworked in both oil production andwater injection), he has workingexperience in well surveillance, well

integrity, well stimulation, well completion andcommissioning, and surface facilities. Currently, Hashem isworking as an ‘Uthmaniyah area Production Engineer inSaudi Aramco’s Southern Area Production EngineeringDepartment.

In 2009, he received his B.S. degree in PetroleumEngineering from King Fahd University of Petroleum andMinerals (KFUPM), Dhahran, Saudi Arabia.

degree in Petroleum

integrity well stimulation,

Mohammed joined

graduated in 2005



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Spring 2016 · 2016-03-21 · Spring 2016 THE SAUDI ARAMCO JOURNAL OF TECHNOLOGY A quarterly publication of the Saudi Arabian Oil Company Journal of Technology Saudi Aramco Contents