Well Intervention and Control

In the last 25 years, we have witnessed the introduction of tech-nology that is nothing short of astonishing—things that most of us would never have imagined during our early days in the field and on the rigs. While the biggest effect clearly has been on overall drilling efficiency—especially real-time information while drilling—it is interesting to look at how technology has affected the well-control aspect of drilling.

Today, we have the ability to look at a computer screen that provides a virtually instantaneous reading of numerous downhole parameters (e.g., annular pressure near the bit, equivalent circulating density, temperature, torque, vibration, and lithology). Advances in surface monitoring have lead to significant improvements in computerized displays of pressures, rates, and volumes, all of which are crucial to maintaining hydrostatic control of the well.

Some may wonder how wells were ever drilled without these high-tech tools. In December 1982, there were 4,530 rigs running in the US vs. approximately 1,800 rigs running in the US today. When those 4,530 rigs were drilling back in 1982, measurement while drilling (MWD) was in its infancy—Schlumberger did not complete their first commercial MWD project until some time in 1980. That means that there were more than 4,500 rigs drilling away, mostly without the benefit of any real-time bottomhole information except for what could be derived from experience-based surface observations.

Anyone remember what a computer looked like in 1982? That was the year Intel introduced its 80286 processor with a blazing 6-MHz speed—the computer used to produce this article runs 6,000 times faster. Obviously, there were no computer screens in the drilling supervisor’s office giving 24-hour graphical and numerical readouts in real time. If there was a computer on site, it was probably busy with a game of pong, or maybe a basic spreadsheet.

Technology has allowed our industry to advance to a point where pressure is manipulated for the purposes of increasing drilling efficiency and reducing for-mation damage. It used to be that any kind of pressure at the surface was a sure sign of a problem. Primary, well control inherently meant the absence of surface pressure. Now we have underbalanced drilling and managed-pressure drilling that seem completely foreign to this long-held concept.

Numerous articles could be (and probably have been) written about the risk/reward aspects of where technology has allowed us to venture. Sometimes it is just interest-ing to sit back and look at where we were not that long ago. You cannot help but wonder where continued advancements will lead over the next 25 years.

David Barnett, SPE, is vice president, Engineering Services for Wild Well Control, a company specializing in firefighting, well-control, and engineering services. He has more than 20 years of drilling, snubbing, coiled-tubing, and well-control experi-ence. Barnett’s experience includes work as a drilling engineer, rig superintendent, snubbing supervisor, and well-control specialist. He has been involved with the planning and implementation of numerous relief-well, high-pressure-snubbing, and well-recovery operations. Barnett was a team leader in the Kuwait project and has worked on well-control projects in many countries around the world. He holds a BS degree in mechanical engineering from the University of Houston and serves on the JPT Editorial Committee.

OVERVIEW

WELL INTERVENTION AND CONTROL

Well Intervention and Control additional reading available at the SPE eLibrary: www.spe.org

SPE 107234“First Subrigfloor HWO Intervention System for a Floating Vessel” by Tim Pollock, BP plc, et al.

SPE 108408“Fishing 10,000 ft of CT From a Deep Gas Well in Saudi Arabia” by Hasan H. Al Jubran, Saudi Aramco

available at the OTC Library: www.otcnet.org

OTC 18614“Using BOPs at Pressures in Excess of the Rated Working Pressure—A Solution for High-Pressure Wells?” by M.E. Montgomery, SPE, WEST Engineering Services, et al.

66 JPT • JANUARY 2008

JPT

A significant increase in formation frac-ture resistance can be achieved as a result of a fracture sealing or plug-ging mechanism induced by a particle “screenout” effect resulting from the drilling fluid being loaded with an adequate amount of narrowly sized granular materials. Such an increase in formation fracture resistance is particu-larly valuable in helping to drill through depleted zones without losing fluid, strengthening the weaker formations that usually require additional casing strings for protection, avoiding lost cir-culation during cementing operations, and drilling high-angle well sections with high mud weights that normally would not be possible because of low formation fracture gradients.

IntroductionLost circulation is perhaps the most costly mud-related drilling problem. Not only is rig time lost, but large volumes of expensive drilling fluids are lost to the formation. Lost circu-lation also can lead to severe well-control incidents. In response, several technologies referred to as “wellbore strengthening” (WS) are being devel-oped to prevent or correct lost circula-tion. WS means that the breakdown pressure of the wellbore is greater after the treatment than before. These meth-ods include use of special granular

material, heating the wellbore, and use of rigid-plug-forming pills. The full-length paper focuses on a WS method that uses mud with special bridging and fluid-loss formulations.

In the mid-1980s, a joint-industry project (JIP) was conducted to deter-mine why oil-based mud apparently caused a lower fracture gradient than water-based mud (WBM). Data from this JIP were analyzed, and it was determined that they did not fit ordi-nary fracturing models of the time. These researchers noted that certain lost-circulation materials (LCMs) actu-ally seemed to increase the pressure required for fracture propagation to more than what was seen with untreat-ed drilling mud. They conducted labo-ratory tests outside the JIP to verify their observations. The result was the development of a loss-prevention mate-rial (LPM) that was found to inhibit the extension of a fracture tip.

LPM was tested in the field several times and was quite successful. It was able to increase the wellbore break-down pressure in several cases, and subsequent application of the technol-ogy has allowed a casing string to be skipped in several cases. The technique affects only the near-wellbore break-

down pressure, not the far-field frac-ture gradient.

Case HistoriesThe full-length paper presents four case histories that provide a sampling of the various ways in which the WS technique can be applied. Although the optimal way to apply this tech-nique is to drill the weak zone with the granular material carried in the entire mud system (the drill-ahead method), three of the four examples are actually cases of the formation-integrity-test (FIT) -type method.

Case A. Wells in one field had lost circulation zones in two sandstone formations because neither formation could withstand mud densities greater than 9.0 lbm/gal. The limestone reser-voir below them is pressured at 10.1 to 10.5 lbm/gal. The traditional solu-tion had been to set an 8,050-ft string of 7-in. intermediate casing, drill the remaining 650 ft of wellbore, and then hang a liner from the intermediate cas-ing across the pressured limestone res-ervoir. This approach has two distinct disadvantages. First, if the well turns out to be a dry hole when total depth (TD) is reached, an expensive 8,000-ft

This article, written by Assistant Technology Editor Karen Bybee, con-tains highlights of paper SPE 105809, “Further Development, Field Testing, and Application of the Wellbore-Strengthening Technique for Drilling Operations,” by Giin-Fa Fuh, SPE, andDave Beardmore, SPE, ConocoPhillips Co., and Nobuo Morita, SPE, Waseda U., prepared for the 2007 SPE/IADC Drilling Conference, Amsterdam, 20–22 February.

Wellbore-Strengthening Technique for Drilling Operations


Fig. 1—Well C WS treatment design; TVD=true vertical depth, MD=measured depth, and MW=mud weight.

For a limited time, the full-length paper is available free to SPE members at www.spe.org/jpt. The paper has not been peer reviewed.

JPT • JANUARY 2008 67


string of casing has already been run and cemented in the wellbore. Second, the casing/liner combination is more expensive than a single string of pro-duction casing.

The first attempt was to eliminate the 8,050-ft intermediate-casing string while drilling Well A1. The decision was made to leave the weak-sandstone intervals exposed to the 10.0-lbm/gal mud used to drill the pay. In doing so, it was assumed that the occurrence of lost circulation was inconsistent within the weak zones in nearby fields and that lost circulation in this field might not be a problem. Lost circulation occurred into the uppermost weak sandstone, and the resulting reduction in hydro-static head allowed an influx of oil and gas from the limestone producing for-mation. Although the well control was skillfully managed without incident, the hazardous conditions necessitated finding a lower-risk solution, and LPM technology for WS was presented as a potential solution.

Because of apprehension about the effectiveness of the LPM concept, a modified approach was pursued in Well A2. An 83/4-in. hole was drilled out from under the 95/8-in. interme-diate-casing string at 3,500 ft. Fresh water was used to drill to 6,450 ft, at which point the wellbore was displaced with a 9.2-lbm/gal LPM mud consisting of salt gel, starch, and LPM. The LPM was 40 lbm/bbl of 30/60-mesh walnut hulls. As a precaution, the decision was made to drill into the top of the weak zones with weighted LPM fluid and determine the effectiveness of the LPM technology without exposing the several hundred feet of the entire weak interval to an excessive mud weight. If lost circulation occurred at the top of the weak zones and the LPM was ineffective, the test would be discon-tinued, and the mud weight could be reduced to less than 9.0 lbm/gal. The intermediate hole then would be drilled to 8,050 ft, and the 7-in. inter-mediate-casing string would be set as usual. However, no losses occurred during drilling operations when the mud weight was increased from 9.2 to 10.1 lbm/gal with the addition of drilled solids and salt. The well was drilled successfully to TD at 8,700 ft, and 51/2-in. production casing was run and cemented. As a result, a net WS of at least 1.1 lbm/gal was achieved in this case.

For the 2,250 ft of hole that was drilled with 30/60-mesh LPM in the mud, 60-mesh screens were used on the shakers to provide some mud cleaning for that long interval. Some of the LPM that was removed by the shakers was recycled into the mud, and significant additions of new LPM were made to replace what was not recovered from the shakers. This was operationally very difficult for such a long section.

To avoid losing circulation during the cement job, plans were to perform a two-stage job—placing a 15.6-lbm/gal cement from TD up to 8,000 ft dur-ing the first stage and then circulat-ing a low-density foam cement from 8,000 ft up into the surface casing. The foam cement would limit hydrostatic head, preventing lost circulation into the exposed weak formations below 6,500 ft. After completing the first stage, the differential valve tool at 8,000 ft was opened and approximately 15 bbl of mud was pumped before circulation was stopped to switch from service-company pumps to the rig pumps (i.e., plans were to circulate for approxi-mately 4 hours before beginning the second-stage foam-cement job). When attempts were made to reinitiate cir-culation, complete losses occurred as the result of a pressure surge, and circulation was never recovered. It was estimated that at the time, the spacer and some of the cement from the first stage were directly opposite the weak formations. The pressure surge from breaking circulation caused a fracture to develop, and because the spacer and first-stage cement slurry did not contain LPM, there was no way to prevent the fracture from propagating. Fortunately, subsequent logging indicated top of cement at approximately 6,640 ft (near the top of the weak sandstones), so the producing zone was protected and iso-lated sufficiently.

It would have been preferable to avoid the lost-circulation problems experienced during the cementing operations. However, the lost-circu-lation problems clearly proved that including LPM in the drilling fluids did prevent lost circulation from occur-ring when drilling through the weak formations. Complete circulation loss during the cementing phase indicated that lost circulation also would have occurred during the drilling phase because the hydrostatic head caused by the 10.2-lbm/gal mud used while drill-

ing was greater than that estimated to be applied in the annular space during cementing when the lost-circulation problem occurred.

Several significant changes were made to the well plan before drilling the next well. Because lost circulation was prevented while drilling Well A2, a more aggressive plan was used to drill Well A3. A 77/8-in. bit was used to drill a smaller production hole out of the smaller 85/8-in. intermediate-cas-ing string set at 3,500 ft. Fresh water was used to drill through the weak formations, and the hole was displaced above the top of the pay at 8,500 ft with the same type of LPM drilling fluid used to drill Well A2. Because of the higher formation pressure at this loca-tion, the mud weight was increased to 10.5 lbm/gal. The shakers were bypassed for this short 200-ft interval to allow the LPM to remain in the mud system. No losses were detected at any time during drilling or casing operations, and the well was completed successfully and put on production. In this field case, a minimum of 1.5 lbm/gal in WS was achieved and use of LPM was proved to be effective in inhibiting fracture ini-tiation and propagation in the depleted formations. A 15 to 20% cost savings on this well was attributed to the use of LPM technology. Modification of the well plan to drill smaller holes also resulted in higher penetration rates, reduced drilling-fluid volumes, less cut-tings waste, and improved wellbore sta-bility. Another significant change made for the Well A3 application was to include LPM in the cement formulation at the same concentration used in the drilling fluid. This change prevented lost circulation during the two-stage cement job, yielding a competent col-umn of cement up into the surface casing. After using LPM successfully on Wells A2 and A3, the technology was used in subsequent wells drilled in the same area. In each of the wells, the LPM technology was used to eliminate the intermediate-casing string and to slim down the diameter of the wellbore.

Case C. Well C had a weak zone at TD with high mud weight required for shallower-zone stability. Well C is one of many directional wells with a hori-zontal production section drilled from a central location in an existing field. The 81/2-in. intermediate section is drilled with a WBM at a sail angle of approxi-


mately 65° and into the pay with a final inclination of 90°. Then, 7-in. casing is run and cemented at TD. The produc-tive sandstone reservoir is depleted in some areas, but with the usual 9.8- to 10.0-lbm/gal mud in the intermediate hole section, losses typically do not occur during drilling. While running the 7-in. casing to bottom, mud is rou-tinely circulated at three depths to aid in getting the 7-in. casing to bottom. Occasionally, losses occur during run-ning and cementing the casing.

While drilling Well C, shale caving began to occur in a shale zone above the pay sand. Although the intermedi-ate-section TD was reached, the caving hole section was abandoned and had to be redrilled. The shale caving was con-trolled by increasing the mud weight to 10.0 to 10.6 lbm/gal. On the basis of experience and annular-pressure-drop modeling, losses were not expect-ed while drilling to TD. Equivalent circulating densities (ECDs) would not exceed 11.9-lbm/gal equivalent mud weight (EMW). But losses were expected while running and cementing the 7-in. casing, when ECDs would approach 13.6-lbm/gal EMW.

After discussing the situation, the team developed the idea of spotting a mud pill containing an effective amount of LPM on bottom across the pay sand before pulling out of hole with the drillpipe before running the casing (Fig. 1). The concept was that when the high ECD was applied to the hole during circulation of the casing on the way to TD, the WS material would inhibit fracture growth, prevent major losses, and possibly strengthen the wellbore before the cement job. In this case, getting cement 2,300 ft above the shoe was a regulatory requirement for this waterflood injection well.

Formulation of the WS pill to be spotted on bottom was similar to what had been successful before. The plan was that the pill would stay on bottom while the drillpipe was pulled out of the hole and while the 7-in. casing was run to bottom. The pill would be circulated out of the well when the 7-in. casing got to bottom and would be circulated before cementing.

The main risk of this WS application was that if the pill failed to strengthen the pay sand, it was likely that there would be lost circulation while run-ning the casing or during the cement job. This would necessitate a remedial

cement job because of the regulatory cementing requirements.

The pay-sand fracture gradient varies with local pore pressure. The reservoir has linedrive producers and injectors. Depending on the nature of the perme-ability of the reservoir and its connec-tion with either injectors or producers at the point of penetration, the pay sand could have a higher (or lower) than normal fracture gradient. The fracture gradient of the pay at virgin pore pres-sure is approximately 13.0 lbm/gal. The 7-in.-casing shoes typically undergo a 12.5-lbm/gal FIT before drilling the horizontal section. Approximately one-fourth of the wells produce leakoff before reaching 12.5-lbm/gal EMW.

The intermediate section was drilled to TD (15,844 ft) with 9.7- to 9.8-lbm/gal mud. Caving shale and packoffs became a serious problem. Mud weight was increased, and some breathing (loss of mud followed by return of part of the lost volume when pumps are shut off) was noted at a 10.6-lbm/gal mud weight. However, it is believed the losses were aggravated by numerous packoff instances. This original hole had such bad caving shale that a cement plug was set over the bottom 2,000 ft. The hole was redrilled with 10.0- to 10.6-lbm/gal mud. At TD of the section (15,758 ft), the WS pill was spotted on bottom to cover the pay sand fully, with some additional volume in case some minor losses occurred. The drillpipe was pulled above the pill, and 11.0-lbm/gal mud was circulated and conditioned above the pill with no losses. The pressure-while-drilling tool in the hole recorded a maximum sus-tained ECD of 11.8-lbm/gal EMW while circulating, with spikes to 12.1-lbm/gal EMW during packoffs.

The 7-in. casing was run in the hole, with circulation conducted at 3,453 ft (surface shoe), 6,945 ft, 10,420 ft, and 13,828 ft at 3 to 4 bbl/min. The casing was reciprocated during these stops. The casing was worked through tight hole at 14,965 to 15,640 ft. No losses occurred while running or circulating casing. At TD, the casing was circulated at 4 bbl/min, and the mud weight was reduced from 11.0 to 10.6 lbm/gal. The casing was cemented with a 12.5-lbm/galspacer and a 15.8-lbm/gal cement slurry at 4.5 bbl/min with no losses. The cement simulator indicated that the maximum ECD was approximately 13.6 lbm/gal, which is well above the

normal 11.8- to 13.0-lbm/gal fracture gradient for the pay sand. The treatment was considered a success because there were no losses, and a remedial cement job was avoided.

DiscussionThe mechanism of increased fracture resistance or WS depends highly on the LPM concentration used in relation to the degree of formation permeabil-ity. Numerical modeling is in progress to analyze the effect of LPM and its concentration on fracture propagation during the dehydration of LPM and mud solids. The modeling indicates that at a low LPM concentration (i.e., 5 to 10 vol%), the LPM dehydrates and forms a sealing barrier around the fracture tip (in permeable formations) that significantly increases the apparent fracture toughness to prevent fracture propagation. For a medium LPM con-centration (i.e., 10 to 30 vol%), the LPM dehydrates at the mouth of the induced fracture for permeable and less-permeable formations, and acts like a sealant and increases the rupture strength of the borehole. At a much higher LPM concentration (i.e., 30 to 50 vol%), the LPM would plug the mouth of the induced fracture even for formations with zero permeability because of geometrical factors

All four of these case histories in the full-length paper were conducted in what would be described as “hard rock.” None were conducted in uncon-solidated sands, silts, or clays.

The drill-ahead type of application should be the most effective because the LPM always is available to inhibit fracture growth. However, long hole sections may preclude its use because of solids buildup in the mud. Therefore, development and understanding of the FIT-type method is warranted.

One of the most important aspects of either of these methods that use the special granular material is that they are preventive treatments. Theoretically, the granular material will work best only on newly forming fractures. It is conceivable that the suitable concen-trations of granular materials might be more effective than other LCM mixes in situations of induced- or natural-frac-ture lost circulation that have already occurred, but theoretically, and so far in practice, they have not been able to strengthen formations that have already suffered large losses. JPT

The full-length paper demonstrates that wellbore strengthening in shale is fea-sible. A treatment pill was developed in the laboratory and field tested suc-cessfully at a US land-based location. The treatment consisted of a blend of particulates (known as stress-cage sol-ids) and proprietary crosslinked gelling polymers that set with time. Properties of the system such as compressive strength, adhesion to shale, and sensi-tivity to temperature and pressure were evaluated. Modeling work was con-ducted to engineer the size and con-centration of bridging solids required.

IntroductionDrilling in depleted zones, or inter-vals where high-pressured formations are interbedded with normally and abnormally pressured layers, has cre-ated the need for these strengthening technologies. The goal is to increase the fracture resistance of weaker for-mations and thereby avoid mud losses, wellbore instabilities, and the poten-tial loss of the drilled interval. The primary consequences of these unde-sired events are an increase in nonpro-ductive time and associated costs. In addition to avoiding these problems, the economic benefits that wellbore strengthening can provide are the pos-sible elimination of a casing string or, more importantly, the ability to reach deeper reservoir targets.

One of the most popular wellbore-strengthening technologies is induc-ing an increase in wellbore stresses by use of sized-particulate additions to the drilling fluid. The common name for this approach is “stress caging.” The principle is to increase the hoop stress around the wellbore by using fractures to cause stress changes in the rock. These fractures would be held open with bridging material, thereby creating the stress-cage effect, or strengthening of the wellbore. This bridge of particles across the mouth of the fracture must have low permeability to provide pres-sure isolation of the fluid in the well-bore from that in the fracture, thus pre-venting any further fracture elongation. The degree of stress caging relative to the native stresses is a function of both fracture width and radius and the rock properties (i.e., Young’s modulus and Poisson’s ratio). To achieve this effect, the proper type, size, and amount of loss-prevention material (LPM) must be used. Using the stress-cage concept and associated factors, drilling fluids can be designed to maximize this strengthen-ing effect and minimize losses and other problems encountered when drilling significantly above the fracture gradient. In fact, use of these LPMs for wellbore strengthening has led to several comple-mentary technologies.

Although the stress-cage approach is used widely, the application primar-ily has been confined to permeable formations, even though strengthening impermeable rocks (e.g., shale) also often is required. The key to stress caging shale would be to design a tech-nology (i.e., chemistry, technique, or both) whereby once the sized bridging particulates prop open the fracture, they cannot be removed easily. One approach is to transport the bridging particulate in a settable medium that solidifies the fracture. The solidification

will prevent further seepage of fluid through a leaky seal on the bridge, will prevent flowback toward the wellbore when hydrostatic pressure is reduced temporarily, and will help bear the stress across the fracture. This solution can be enhanced further if the mate-rial also shows a propensity to adhere to shale. In this manner, the propping particulate can be introduced to the fracture with the proper size and con-centration, allowing a desired set while avoiding undesired pressure transmis-sion and then adhering to the shale fracture, thus providing a permanent bridge at the opening of the fracture.

Field TrialsBP has conducted several stress-cage trials in shale. The previous trials car-ried out in the US Arkoma basin were somewhat encouraging. Pressures greater than 5 lbm/gal above the forma-tion fracture pressure were achieved as long as the stress-cage pill remained in the hole. The pill was formulated in oil-based mud (OBM) and contained sized marble and graphitic bridging solids, but was of a nonsetting type.

When the pill was displaced after the squeeze, and regular mud was circu-lated, the strengthening effect was lost. It appeared the bridging particles were not held sufficiently strongly within the fracture and subsequently were stripped out.

Gel System. A new trial was conducted in the Arkoma basin to test the novel gel system, with the goal of achieving a more permanent strengthening effect. The test was conducted in a vertical well, across 50 ft of Atoka shale in an 83/4-in. hole at approximately 4,020 ft. The shale was directly below the 95/8-in.-cas-ing shoe. The Atoka formation is a fairly unreactive brittle shale. An OBM with a 9.3-lbm/gal density was used.

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 110713, “A New Treatment for Wellbore Strengthening in Shale,” by Mark S. Aston, SPE, Mark W. Alberty, SPE, and Simon Duncum, BP plc, andJames E. Friedheim, SPE, and Mark W. Sanders, SPE, M-I Swaco, pre-pared for the 2007 SPE Annual Technical Conference and Exhibition, Anaheim, California, 11–14 November.

Wellbore Strengthening in Shale





Baseline Data. A 1,928-psi forma-tion-breakdown pressure was mea-sured, and upon shut-in, the pres-sure was bled back to approximately 1,500 psi. As expected, the bleed-back value coincides roughly with the reopening pressure (1,525 psi) seen on repressurization. The differ-ence between initial breakdown and reopening of approximately 400 psi (1,928−1,525 psi) represents the ten-sile strength of the rock.

The bottomhole shut-in tempera-ture was logged as 107°F, which was considerably lower than the predicted 120 to 127°F. Rather than redesign-ing the chemistry of the gel system on short notice, the decision was made to extend the shut-in period. Therefore, long shut-in times of approximately 20 hours were needed for the trial.

Pill Formulation and Placement.The bridging package for the pill was designed by running in-house soft-ware that predicts fracture widths from geophysical data. A fracture-opening width of 640 μm was predicted, which would allow the wellbore pressure to exceed the minimum horizontal stress by 500 psi. The bridging-solids blend then was selected to cover a wide range of sizes (approximately 2 to 800 μm), allowing for possible variations in frac-ture width and ensuring that a good seal was obtained on the fracture. A high concentration of bridging solids included 25 lbm/bbl of coarse mar-ble, 25 lbm/bbl of graphitic solids, 20 lbm/bbl of medium marble, and 20 lbm/bbl of fine marble.

Additional fine marble was added as required to increase the weight of the pill to the desired value (10.5 lbm/gal). Laboratory work had shown this to be beneficial, and it would increase the compressive strength of the set material.

A balanced-plug technique was used. The procedure was to pump a 10-bbl diesel spacer, followed by 16 bbl of treatment, and then 2 bbl diesel so that column heights/densities were bal-anced in the annulus and drillpipe after displacement. Foam wiper balls were placed on either side of the treatment.

First Gel-Pill Application. In the first attempt, the pill was squeezed for 19 hours at 2,000-psi surface pressure (72 psi above the initial formation-breakdown pressure). The pressure

held during the squeeze, but after drill-ing out the set treatment and circulating clean, there was only a limited strength increase. The fracture opened again at 1,800 psi. It seemed that insufficient squeeze pressure had been applied to force the bridging-solids/gel system fully into the mouth of the fracture.

Second Gel-Pill Application. The sec-ond pill formulation and procedure were similar to those of the first pill, except a higher squeeze pressure was applied. A 2,500-psi squeeze pressure was used, which was approached in stages over a 2-hour period while the treatment was still liquid. The pres-sure actually climbed to approximately 3,000 psi toward the end of the shut-in period, most likely as a result of an increasing wellbore temperature and the heating of surface lines (night vs. day temperatures). It is remarkable that the formulated pill could hold the 2,500 psi while still fully liquid, but it was expected that it could hold high pressures (3,000 psi) once set.

After drilling out, survival tests were carried out. For each survival test, mud was circulated for a set period and the bottomhole assembly was rotated and moved up and down through the strengthened shale to avoid washout. The survival was then assessed by formation-integrity-test (FIT) testing. The FIT pressure was taken to 1,400 psi initially to establish a baseline, and then to 1,700 psi in Tests 1 through 3 (175 psi above the fracture-reopening pressure), and up to 2,080 psi in Test 4 (555 psi above the fracture-reopening pressure).

Tests 1 through 3 show that a strengthening effect was indeed achieved, and that the treatment could survive increasing periods of mud cir-culation. The total circulation time at the end of Test 3 had been 2.75 hours at half the normal circulation rate—220gal/min. Even more impressive is Survival Test 4. In this final test, the circulation rate was increased to 440 gal/min for a further 2 hours, and a final series of FIT tests was performed. The surface pressure was increased in stages and reached an impressive 2,080 psi before the test was termi-nated. This is approximately 150 psi greater than the original formation-breakdown pressure (1,928 psi), and 550 psi more than the fracture-reopen-ing pressure. This value is in fact close

to the original design value for the pill. The drilling team preferred to leave the formation in a strengthened condition, and so it was not possible to increase the pressure further to determine the actual breakdown point.

DiscussionThe slope of the shut-in curves for the various FITs was quite variable. Accordingly, obtaining a low-pressure (1,400 psi) baseline for each FIT test was desirable because this is less than the fracture-reopening pressure and can be used as a reference point; doing so helps avoid erroneous conclusions. Some pressure decay on shut-in is nor-mal and can be caused by a number of effects, including temperature changes, seepage of fluid into the fracture, or leaks introduced in the equipment. Hence, variations between different FIT tests might be expected.

Survival Test 3 produced a remark-ably flat shut-in pressure, and the big-gest contrast with this was Survival Test 4 where there was a fairly steep slope on shut-in. The slope in this final test does not change significantly as the pressure is increased and, most impor-tantly, is similar to that of the reference test (1,400 psi). Therefore, the authors concluded that the slope does not imply failure of the stress cage and is most likely caused either by differences in the cooling of the well as a result of differences in circulation times or by a leak in the system introduced between the different circulation stages.

Conclusions1. Shale can be strengthened reliably

by use of stress-cage techniques using a settable pill containing bridging solids with sufficient compressive strength and shale-adhering qualities.

2. Proper design and field implemen-tation of this technology are essential to creating stress cages successfully in shale.

3. Wellbore strengthening through stress caging can be accomplished without the dependence upon fracture collapse caused by leakoff, by maintain-ing a bridge at the mouth of the fracture and preventing additional fluid leakage into the fracture.

4. The demonstration of the feasibil-ity of the application of stress cages to shale opens the door for further devel-opment and application of stress cages in shale. JPT

The full-length paper presents equa-tions and guidelines for determining requirements for pump rates, number of wells, and kill fluids required to kill a blowout. A comparison with selected field cases demonstrates that the for-mulated guidelines match the require-ments to actually kill these blowouts. This comparison gives confidence that the guidelines presented are a good starting point for contingency plan-ning. Several blowout scenarios for a giant North Sea gas field are exam-ined to demonstrate application of the guidelines.

IntroductionBecause of advances in drilling and production technology, blowouts have become an increasingly rare phenom-enon. A report published by the United Nations Environment Program that cites statistics from the US Gulf of Mexico (GOM) and the North Sea shows the probability of shallow-gas blowouts in exploration wells to be approximately one in every 200 wells; for workover operations, one in every 2,500 wells for oil wells and one in every 1,000 wells for gas wells; and for infill wells, less than one in every 10,000 wells drilled. Because of this, blowout prevention is a top priority in drilling and well intervention. A con-tingency plan must be formulated before spudding development wells to limit the consequences of a blowout by prescrib-ing an adequate emergency response to a possible well-control incident. On the

basis of the emergency-response plan, preparations can be made to take action rapidly after an incident is reported. Such preparations would include ensuring the availability of a nearby rig for drilling a relief well, sufficient tubular-goods stock to complete a relief well, and pump capacity to kill the blowing well. With these elements in place, relief efforts can be started quickly, thus reducing the time to regain control of the well. The plan should consider the possible modes of failure and the response to these fail-ures to restore well integrity.

In the majority of cases, “capping” of the well (i.e., replacing the damaged wellhead) is the most efficient method to stop flow from the well. To illustrate, most of the more than 780 wells that were sabotaged and set on fire during the 1991 Gulf War in Kuwait were brought under control within 8 months by capping. With this success, well-control companies demonstrated that even under harsh post-war conditions, capping technology could deal with almost any form of wellhead damage.

Unfortunately, capping is of little use when the wellhead is not the point of

outflow, is inaccessible, or is damaged to the extent that repair is impossible. Examples of these situations include the following.

• Underground blowouts, where the flow of hydrocarbons enters a shallow low-pressure zone (e.g., through a cas-ing leak). In the case of a shallow leak, the fluids may reach the surface some distance from the well.

• Subsea wells.• Wells and platforms that have suf-

fered such damage that a safe position cannot be created for staff to work on the well. The Bay Marchand incident, with 11 wells on fire on a single plat-form, was an example of this situation.

In these cases, to restore the mechan-ical integrity of the well, inflow must be inhibited by balancing the pressure of the producing formations with a fluid column in the well or by blocking the entry of oil and/or gas into the well by saturating the near-wellbore region with water or brine.

The latter method, called “flooding,” requires the injection of large amounts of water into the near-wellbore forma-tions through one or more relief wells

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 105612, “Hydraulic Blowout-Control Requirements for Big-Bore and HP/HT Developments: Validation With Field Experience,” by P. Oudeman, SPE, Shell Intl. E&P, prepared for the 2007 SPE/IADC Drilling Conference, Amsterdam, 20–22 February.

Hydraulic Blowout-Control Requirements


0

50

100

150

200

250

4 5 6 7 8 9 10 11

Conduit ID, in.

Pu

mp

Ra

te, b

bl/

min

X > 1

X = 0.75

X = 0.5

X = 0.25

Fig. 1—Required pump rates vs. blowout-conduit inside diameter (ID).




and is usually a cumbersome and time-consuming process. To illustrate, in Bay Marchand, this required drilling wells to within 25 ft of each of the blowing wells. Ten of the wells were killed this way. One remaining well had to be capped after 100,000 bbl of seawater was pumped without any noticeable effect. Hence the first process, hydraulic blowout control, usually will be the preferred option.

For successful hydraulic blowout control, often referred to as “dynamic kill,” it is essential that kill fluids be pumped downhole into the blowout well at such a rate that the well can no longer lift oil and/or gas to surface and the well ceases to flow once sufficient pressure has built up at the sandface. This means that for contingency plan-ning for a new well, two primary ques-tions need to be answered.

1. What kill fluid should be pumped into the well and at what rate to control the well flow when mechanical control is not an option?

2. Will it be technically feasible to pump this rate into the well given the limitations of the kill string and pump equipment?

For normally pressured, medium-sized oil and gas wells, the feasibility of hydraulic blowout control has been proved in a large number of reported cases. Considerably less experience is available in areas such as high-pres-sure/high-temperature wells, big-bore gas wells, and highly prolific wells such as long horizontal wells.

Answering the primary questions of hydraulic blowout control for these types of wells, with their high blowout potential and associated potential dam-age, is of utmost importance. Here, the answers will be sought by applying the validated knowledge obtained in killing “conventional” well blowouts to less-conventional wells. This approach will indicate particular areas of concern and provide general guidelines for the design of a relief well and the kill job. These can be considered a good starting point for the relief-well and kill-job design.

The full-length paper presents simpli-fied equations for the minimum pump rate required to kill overpressured wells and big-bore wells, required hydraulic horsepower of the pump, and required pumping time.

Comparison With Field CasesIxtoc 1. Ixtoc 1 was 58 miles north-west of Ciudad del Carmen in the

GOM in 165 ft water depth. In June 1979, control was lost when the well reached 11,900 ft, and total losses were observed. The well blew out after trip-ping out the drillstring, and the rig was evacuated when it caught fire. This was the beginning of a blowout that lasted for 9 months and 22 days, a period over which an estimated 4.2 million bbl of oil were spilled into the GOM, the second-largest oil spill ever after the deliberate release of approximately 5.7 million bbl in the Persian Gulf dur-ing the 1991 Gulf War.

The well was blowing through 95/8-in. casing to surface. The exact pressure was unknown, but the fact that total losses were experienced at 1.12-specific gravity (SG) mud weight suggests that the pressures were close to hydrostatic. According to Fig. 1, this requires a kill rate of approximately 140 bbl/min. Static formation pressure, assuming a hydrostatic gradient, exceeded 5,000 psi [i.e., the maximum pump rate that could be achieved through a well with 95/8-in. casing and 5-in. drillpipe, 132 bbl/min (Fig. 2 in the full-length paper), was insufficient]. At least two relief wells were required.

Two relief wells, Ixtoc 1-A and Ixtoc 1-B, were spudded. Ixtoc 1-B intersected the blowout first, and injection of sea-water with rates averaging 50 bbl/min started right away. Although this had a positive effect on the amount of oil pro-duced, it did not kill the well. Rates as high as 100 bbl/min were achieved with the 14,000 hp available, but these could not be maintained because of the rough seas, which are common in the Bay of Campeche during winter. Two months later, Ixtoc 1-A intersected the blowout. Attempts were made to kill the blowout by simultaneously pumping down the two relief wells with mud density as great as 1.8 SG, but without success. Unfortunately the pump rates are not specified in the literature. Gradually, the water cut of the produced fluids increased. Continued pumping of sea-water, possibly in combination with water breakthrough in the well, finally killed the blowout on 17 March 1980.

Fateh L-3. The Fateh L-3 develop-ment well offshore Dubai had reached 4,180 ft when the kick occurred in the 171/2-in. wellbore. A 30-in. conduc-tor had been driven to 450 ft, and a 20-in. casing was set and cemented at 1,310 ft. Kick-control efforts were

abandoned and the rig was evacuated when gas broke around the 20-in. shoe and bubbled up under the platform. Eight days later the gas ignited, and in 2 weeks, the rig and platform disap-peared into the Persian Gulf.

The gas originated from the Asmari limestone formation, which had a 115-ft gas column at the position of L-3. This formation is vuggy and frac-tured, with permeabilities of several hundred md. The 171/2-in. hole was open to flow of gas and water from this formation. A hole this size from top to bottom would require a kill rate of more than 700 bbl/min and 6 relief wells. However, the drillstring was left in the hole, which gave an additional resistance to flow. Flow was not directly to surface but around the 20-in.-casing shoe and through the for-mations surrounding the well. Heavy kill fluids could be used to reduce the kill rate required. A more refined analy-sis taking these factors into account indicates a kill rate of approximately 300 bbl/min for seawater. Eventually four relief wells were drilled, and dur-ing five kill attempts, fluids (including polymers to combat fluid losses) were pumped downhole into the well at rates as high as 230 bbl/min without success. The well bridged and ceased flowing approximately 7 months after the blowout started.

This case demonstrates that hole size is a major factor for blowout control. Whereas high pressure can be coun-tered by high-density kill fluids, a lack of resistance to flow will in all cases require high pump rates.

Arun-C-II-2. The blowout of Mobil Indonesia’s Arun C-II-2 is considered the largest gas blowout ever. The res-ervoir pressure at a 9,650 ft true verti-cal depth (TVD) was 7,100 psi. The temperature was 230°F. The well was blowing 0.6-SG lean gas through the annulus of a 95/8-in. casing and 5-in. drillpipe. Measured depth of the well was 10,210 ft.

In the Arun case, the required 126-bbl/min kill rate was much high-er than the 80 bbl/min calculated or the 118 bbl/min indicated by Fig. 1. Previous authors have attributed this to leakoff in the very-high-permeability reservoir between the relief well and the blowout well. The leakoff resulted in only a fraction of the kill fluid actu-ally flowing up the blowout well.


The discussion of the field cases shows that the theoretical relations between well parameters, such as geometry and pressure regime, and the actual relief effort required are in fair agreement. This allows the final step, quantification of the relief effort required for a proposed development.

Contingency PlanningTo illustrate application of the princi-ples presented in the full-length paper, the case of the Ormen Lange gas field, offshore Norway, will be examined. The Ormen Lange field, discovered in 1997, is in the Storegga slide area. Water depth is 2,789 to 3,089 ft. It is the second-largest gas field in Norway. With gas reserves of close to 13 Tcf and development costs of approxi-mately USD 0.5 billion, Ormen Lange ranks as the largest development in the European offshore arena. The res-ervoir is approximately 24 miles long and five miles wide, approximately 10,000 ft below the surface of the sea and 6,600 ft below seabed level.

Anticipated production capacity is approximately 38,000 to 53,000 B/D

condensate and 2,500 MMscf/D gas to be produced by 24 subsea wells in four seabed templates. Condensate/gas ratio is estimated at approximately 18 bbl/MMscf; water production is con-sidered negligible. The 150-ft-thick sands with an average permeability of 500 md are normally pressured (4,200 psi).

A subsea well at a depth of 2,788 ft below mean sea level will blow out against a surface pressure of 1,270 psi, assuming seawater SG of 1.03. This means the effective reservoir pressure is 2,930 psia. For a vertical distance of 6,562 ft between the reservoir and the wellhead, this gives a hydrostatic ratio, X, practically equal to one.

Several scenarios were examined, and predictions were made by use of the equations and figures presented in the full-length paper. Scenarios 1 and 2 were blowouts to the seabed during production through 95/8-in. tubing and 7-in. tubing, respectively. Scenario 3 was a blowout during light interven-tion. Scenarios 4 and 5 were blow-outs to the seabed during drilling with 133/8-in. casing set at 6,890 ft TVD and with 95/8-in. casing set right above the

top of the reservoir, respectively. Two subcases were considered for Scenarios 4 and 5.

Of the scenarios considered, Scenario 2, blowout through 7-in. tubing during production, will have the highest resis-tance to flow and will have the lowest required pump rate. The method pre-sented in the full-length paper indicates that 70 bbl/min of seawater will be required to kill this well. A single relief well will be sufficient, and 6,000 hhp will be needed.

The worst case is Scenario 4 with 133/8-in. casing and flow in the open hole/casing annulus with no drillpipe in the hole, and relief-well intersection just below the 133/8-in. casing. This scenario requires 310 bbl/min. Three relief wells would be required. High-density kill fluids could reduce this to two wells. Only when the reservoir pressure drops to less than 2,470 psi, reducing the hydrostatic ratio to less than 0.4, would a single relief well be sufficient to kill the blowout. Early development with big-bore wells will have to be considered carefully in this case.

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