Copyright 2001, Society of Petroleum Engineers Inc. This paper was prepared for presentation at the 2001 SPE Annual Technical Conference and Exhibition held in New Orleans, Louisiana, 30 September–3 October 2001. This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.

Abstract Sand Management is an operating concept where traditional sand control means are not normally applied, and production is managed through monitoring and control of well pressures, fluid rates and sand influx. In the last four years, Sand Management in conventional oil and gas production has been implemented on a large number of wells in the North Sea and elsewhere. In almost all cases it has proven to be workable, and has led to the generation of highly favorable well skins because of self-cleanup associated with the episodic sand bursts that take place. These low skins have, in turn, led to higher productivity indexes, and each of the wells where sand management has been successful has displayed increased oil or gas production rates. Furthermore, expensive sand control devices are avoided and the feasibility of possible future well interventions is guaranteed.

Different analysis and design tools are needed to evaluate sand production probability, to quantify risk reduction, and to establish practical operational criteria for safe and optimum production. Such design tools include the capacity to predict sand production onset, sand quantities and sand production rates, equipment erosion risks, and the conditions at which the sand can be transported inside the production liner and surface lines. Also, an essential tool is a sand monitoring technology to allow real-time quantitative sand flux tracking. The application of these tools and how they help assess risks in Sand Management are illustrated through field examples in this paper. Methods of handling the uncertainties and risks are discussed. Data from the North Sea, where active Sand Management was applied to increase well production rates, are presented. Finally, ideas on how to apply sand management and hybrid completions in challenging environments such as

HPHT fields, marginal fields and complex structures are discussed. Introduction This review of the tools of Sand Management is an introduction to the Sand Management approach for optimization of production rates and well productivity. Because of the drawbacks of classical sand control techniques and the risks involved in uncontrolled sand production, Sand Management is proposed as a synthesis of the two philosophies. Furthermore, the challenges of developing complex, marginal and HPHT fields require new solutions. Historical steps in preventing sand production risk. Classical sand control techniques, such as gravel packing, wire wrapped screens, frac-and-pack, chemical consolidation, expandable screens, etc., are based on a sand exclusion philosophy: absolutely no sand in the production facilities can be tolerated. Alternatively, in the absence of means of totally excluding sand influx, the traditional approach is to reduce the production rate to minimise the amount of entering sand.

The decision to exclude or control sand is based on a sand prediction analysis, for example, where the suitability of a perforated liner solution is evaluated based on a no-sand condition [1]. This has led to development of various techniques to predict the onset of sand production [2 - 5].

Thus, sand influx is usually viewed as a factor that limits the production rate (and thereby the cash-flow) through the induced production limitations set by installed sand control methods, production losses due to failures and workovers, and induced production restrictions arising from low maximum sand-free rate limits.

However, sand influx is related to the mechanical failure and dilation of the formation rock and the removal of failed or damaged material [6, 7]. Clearly, the permeability in the wellbore vicinity is increased with respect to the intact formation. This has been verified in a number of situations:

• Well test data show that negative skin values often

develop as a result of a cleaning of the near-wellbore formation of sand [8];

• Production data in Cold Heavy Oil Production with Sand (CHOPS) show that the productivity index increases dramatically with massive sand production [9, 10]. As a

SPE 71673

The Tools of Sand Management J.Tronvoll, M.B. Dusseault, F. Sanfilippo, and F.J. Santarelli, SPE, Oifield Rock Mechanics Integrated Services (ORMIS)

2 J. TRONVOLL, M.B. DUSSEAULT, F. SANFILIPPO, F.J. SANTARELLI SPE 71673

consequence, in those heavy crudes (µ = 1000 – 15,000 cP), low-rate Alberta and Saskatchewan oil wells, sand production of 2-8 vol. % is not only tolerated, but even provoked as a mean of continuous well stimulation [11].

• Scaled model experiments of producing perforation cavities show increased post-sanding productivity trends in different sandstones [7].

A Sand Management Philosophy. The Canadian heavy-oil wells remains to-date the most extensive field validation of the reliability and cost-effectiveness of Sand Management. This approach can be considered a fine-tuned combination of techniques to define and extend the safety limits within which sanding can be considered operatively tolerable. In this way the expenses of a too-conservative approach are avoided or delayed, and at the same time increased well productivity from continuous well clean-up is achieved.

Table 1 is a critique of different methods used for dealing with sand production: generally, sand control represents high cost - low risk solutions, Sand Management leads to low-cost solutions, but it also involves active risk management.

Risk management requires reliable analysis of the “Sand Life Cycle”, starting with predicting formation conditions conducive to sanding, and ending with ultimate disposal of the produced material at surface. These techniques are based on:

• An extensive field data acquisition campaign; • Theoretical modeling of the involved physical processes; • Active monitoring and follow-up on production data; and, • Well testing to optimize production rates.

Also, the techniques will help the production engineer in:

• Completion design optimization, and • Risk assessment throughout the well production life.

The ‘Sand Life Cycle' Sand Detachment. The primary phase is the release of sandstone fragments from the formation near the well. This has been thoroughly studied [7, 12 - 16]; many models exist for prediction of sanding initiation conditions [3, 5, 17, 18]. Recent studies suggest that sand detachment may be viewed as a mixed hydro-mechanical process [6, 19 - 22].

First, a producing stratum fails in compression or extension from excessive local stresses at the free surface near the wellbore. The failure arises from excessive drawdown or reservoir pressure depletion; these impose increased effective stresses around the well [1]. Alternatively, sanding may result from formation weakening, perhaps from fatigue effects related to repeated well shut-ins, or from water breakthrough and related capillary or chemical cohesion loss [1, 23].

Second, the yielded material, perhaps remaining attached to the intact formation as a post-failure zone, is destabilized and fluidized by hydrodynamic forces from the fluid flow into the well. These forces vary with time along with local

geometry, and therefore sand is likely to be produced as bursts, rather than as a constant inflow. This has been observed through small-scale laboratory experiments [7, 12, 13, 16], and is also reported to be the case in the field [2, 22].

Transient pressure gradient effects that occur during well shut-in and bean-up and relative permeability changes during water and gas breakthrough [16, 23] are the best known causes for episodic increases in sand influx, as both increase the drag forces acting on the sand in the vicinity of the wellbore.

Sand Transport. Once sand is detached, it follows the fluid stream through the perforations and into the well. Grains and sand fragments (grain clusters stabilized by inter-granular cohesion) are then subjected to competing effects from gravity and hydrodynamic forces. Their final velocity and probability of transport to surface, rather than blocking perforation tunnels or settling in the well sump or horizontal well sections, depend on the balance of these forces. Thus, relevant parameters at this stage include fluid rheology and density, local flow velocities, local geometrical obstructions, sand fragment size, and well inclination. Particularly in long horizontal wells, sand may sediment yet be re-mobilized later as conditions change (e.g. water cut increases, velocity changes). These events may often be interpreted as sanding because of formation failure, rather than a well clean-up process. Sand erosion. Erosion of tubing, flow lines and chokes is strictly linked with the sand transport process. The kinetic energy of the moving particles is transferred to the steel when they impinge on a surface, causing abrasive steel removal. Various erosion risk assessment methods concur that the two main factors determining such risk are the sand rate and the sand fragment velocity [26 - 32]. So, one may expect quite different scenarios, ranging from heavy crude fields where the velocity is low and so is the risk, to HPHT gas condensate fields, where gas expansion and acceleration near the wellhead dramatically increase erosion risk.

Erosion risk is often the main concern with sand production, and is a major technical and economical constraint because it may lead to serious safety problems. Erosion creates a need for regular workovers, and it can force the production rate to be kept below a considered safe limit. These considerations are obviously more important for subsea plants, where workover costs can be unacceptably high. Surface Sand Deposition. Once sand passes the wellhead, it passes through the surface lines, or, for subsea wells, through the sea-line, to deposit in the separator, which must be cleaned and flushed from time-to-time according to the expected average sand rate. The oil-contaminated produced sand is collected and sent to ultimate disposal. For offshore installations it has been dumped into the sea in the past, but this practice is not viewed as an option in future operations.

SPE 71673 THE TOOLS OF SAND MANAGEMENT 3

Environmental Aspects of Sand Management Sand Separation

Sand separation may be conducted at three principal levels: topside at the primary separation facility, at a subsea separation module (for offshore installations), or through a downhole separator in conjunction with oil-water separation. Surface methods include high-pressure horizontal baffle-plate separators, vertical gravitational separators, and centrifugal segregators. In subsea and downhole separation, water-wet sand will normally be separated by gravity and stored or re-injected. Intermediate to oil wet sand may require a specially designed sand cyclone or sand centrifuge. These methods are non-trivial and remain to be field implemented.

Sand Deposition

Sand from separators is directly collected and shipped to a site for disposal, or prepared for re-injection along with produced water. Distant surface disposal may be costly because of transportation and environmental constraints, e.g., prevention of groundwater pollution. One may distinguish three principally different approaches to sand handling:

• For subsea wells, sand may be directed via the gas/oil line

to the platform for later separation using surface facilities; • Separated sand may be temporarily stored subsea for later

disposal; or, • Sand may be re-injected directly at depth along with

produced water or seawater for pressure maintenance.

Note that direct seafloor dumping is deemed unacceptable from an environmental point of view because of the chemical composition of the sand-liquid mixture, in particular the elevated hydrocarbon content. Environmentally positive rules are being adopted by more and more jurisdictions internationally; such practices are recommended to operators, even if they are not compulsory locally. Another option is surface sand cleaning (washing) before disposal. In Canada, central sand washing facilities have failed repeatedly from technical problems (sand wettability issues), high costs (heat or solvent requirements and poor results), and generation of additional waste streams (more dirty, oily water).

Sand concentrations in the produced fluid will vary greatly, and these options each at some time have to be used on a given well or with any single separation unit. This in turn impacts separator design and equipment choices. In other words, handling methods are strongly influenced by the type of Sand Management technique that is being anticipated. Integrated Sand Production Risk Management The Input Data. The first major step to implement Sand Management is a thorough gathering of historical field data and the planning of future data acquisition. Depending on which analyses to conduct and models to apply, a variety of input data is needed. One may distinguish the following data groups and subgroups for predictive analysis and design:

• Reservoir properties • In-situ stresses (magnitudes and directions) • Virgin pore pressure • Depletion level and depletion rates

• Formation properties • Rock strength and deformation properties • Petrophysical properties • Grain size distribution • Mineralogy

• Fluid data • Fluid composition • PVT data

• Well data • Casing and well design, including surface piping • Completion design • Well direction (azimuth and inclination)

Some data are naturally depth indexed, or at least formation specific, whereas other data remain fairly constant throughout a reservoir block. Depending on the data sources, continuous profiles (logs) or discrete profiles (core data) are generated to assess particular reservoir cross-sections.

A second group is linked to follow up and optimisation:

• Well production rates including GOR, WOR • Sand production signals from detectors

These data are needed to calibrate and update predictive models, to enable a proper evaluation of the sand production risk, and to evaluate potential production strategies.

Quantification of Sand Production Risk. Traditionally, sanding risk is perceived as the risk of reaching the operative conditions at which sand begins to enter into the wellbore. It is implicitly assumed that sand will eventually cause unbearable problems and that no effective action can be taken to cope with it but to avoid the sand inflow.

Sand Management extends this concept by assuming that sand production is not always unacceptable, economically or for safety. Table 2 lists different cases and suggests a classification with respect to the risks, but also to the benefits.

The goal is to define the conditions at which each single sand-related problem (steel erosion, perforations plugging, sea-line blockage, separator filling-up, etc.) can occur in each individual case. To achieve this, analysis has to rely on different models and criteria that act as tools to estimate the risk of each individual problem. Integration of these results can define production ranges within which total risk is acceptable, and may help the reservoir and completion engineers to make logical choices to extend these production ranges. Each tool is discussed in the paragraphs below. Predicting Sand Production Onset. This is the classical sand prediction exercise, where critical conditions for a given combination of well and reservoir pressures for different strata

4 J. TRONVOLL, M.B. DUSSEAULT, F. SANFILIPPO, F.J. SANTARELLI SPE 71673

are determined. Models based on depth-indexed data provide a continuous log in terms of critical drawdown or depletion (i.e. beyond which sand production will occur) with respect to onset of sand production (Figure 1). Critical drawdown or critical depletion denotes the sand production onset conditions. The parameters are inter-dependent: low drawdown allows a higher depletion and vice versa. In our example, a model based on such work [17] is applied; it uses a conservative criterion related to the initial mechanical failure of a perforation cavity as observed in laboratory experiments on a variety of formations [7]. In other cases more in-depth studies are performed using numerical models [5, 6]. This allows perforation design optimisation (length, diameter, shot density and phasing) to minimise the stresses acting on perforation cavities. Such analyses are performed only at given depths as mechanical core tests are needed to calibrate the model. Predicting Sand Rate. Sporadic bursts of sand or low sand rates usually do not cause serious operational problems; often they even are not perceived as “sand production”. Predicting the sand rate is therefore essential to establish safe production limits. However, among the Sand Management tools, this is certainly the less developed, and only a few models have been published [21, 22]. Moreover, to our knowledge, none has undergone extensive field validation.

Here we adopt an analytical approach [21] that provides expressions for the forces acting on perforation wall grains. Our approach considers sanding rate as a result of two competing forces: the friction force among grains tending to keep them in place, and the hydrodynamic forces from flowing fluids tending to destabilize them. These forces have different magnitudes according to rock strength, stress concentrations, and production conditions. The model accounts for these differences to estimate the sand rate at different pay zone intervals and to follow sand evolution with time.

This model was tested and calibrated using sand production data from a North Sea well [22]. They analysed the sand rate trend over 120 hours, and during this period, three sand production peaks could be observed, each associated with increases of the applied drawdown. Figure 2 compares the field data published by [22] and the predictions of the model after calibration. Estimating Sand Transport. Sand Management is based on the principle that sand released at the formation face should arrive at surface and not be deposited in the perforation cavities or in the wellbore. This is motivated by the risk of perforation or well plugging with large sand bursts. This means that for a given well and fluid composition, certain production rates must be maintained to allow sufficient transport energy to overcome settlement forces.

In vertical and slightly deviated wells, analytical models based on Stoke's Law work reasonably well; they permit establishment of lower limits for the necessary drawdown at a given fluid composition. Figure 3 shows an example of a sensitivity analysis performed with such a model, where the

maximum sand particle size that can be transported is estimated at different flow rates within the perforated interval of a vertical well, also taking into account the results of a PLT log. Figure 4 shows another example: the velocity of the sand particles within the production liner is estimated for different sizes and different flow rates. Note that this is crucial data to estimate the risk of erosion of the well facilities, and this example shows how different Sand Management tools can be integrated, using the output of one as input for another.

In horizontal and sub-horizontal wells, the interactions among and between sand particles greatly complicates sand transport modeling. To date, quantitative descriptions remain at the stage of academic research. Instead, empirical criteria based on experimental results are largely preferred within the oil industry [25], aiming to just estimate the minimum flow rates that prevent the development of stable sand beds. Estimating Facilites Erosion Rate. The knowledge of facilities erosion risk is the primary information for well management optimization against sand production. However, the physical process is only partially understood and the prediction of the critical conditions has to rely on empirical or semi-empirical models [26 - 32]. Essentially, on the basis of experimental results, we link the erosion rate with the kinetic energy of sand fragments through functions involving other parameters such as:

• Fluid velocity • Fluid density • Size of the sand fragments • Sand production rate • Pipe or conveyance diameter • System geometry • Metal hardness (resistance to erosion)

Usually these criteria are calibrated for locations where the

risk of erosion is higher, such as elbows and tees and in the restricted zones, such as downhole valves and surface chokes.

Analysis defines the upper production rate limits required to prevent an unacceptable erosion rate. Figure 5 shows a typical sensitivity study using one of these criteria [30]. This is an oil-condensate well where the critical oil flow rate was estimated as a function of the pipe internal diameter below and above the bubble point. Well Monitoring for Reliable Sand Management Sand Monitoring

Sand monitoring is a critical aspect of Sand Management. Current sand monitoring methods may be classified as:

• Volumetric methods

• Sand traps may be installed, usually at tees or bends, to capture sand. Sand is measured by disassembling the sand trap, thus it is not a real-time method. Such

SPE 71673 THE TOOLS OF SAND MANAGEMENT 5

techniques have not proven effective, as the majority of the produced sand is normally not captured (North Sea experience indicate a recovery of 1 - 10%).

• Fluid sampling after the primary separator represents an alternative, including centrifugation for water and sand cuts. This is the so called Bottom Sediment and Water measurement (BS&W) done during appraisal well testing or during normal production. However, much sand usually remains in the primary separator and the method sensitivity can not be guaranteed.

• Another idea consists in dismounting the sand separator, jetting it clean from all sand, and quantifying all produced solids. This has been used quite extensively in the Adriatic Sea on gas wells [4]. However, it is limited in terms of accuracy (see point above) and practicality - i.e. the time and manpower required to dismount, jet, and remount the separator.

• A new method used on some North Sea platforms applies an in-line sand cyclone. Sand is effectively separated from produced fluids and stored in a tank. Load cells or other devices on the tank allow a measure of sand accumulation in real time.

• Acoustic transducers installed in the flow system include: • An impact probe installed in the flow line to detect

sand grain impacts; and, • An acoustic collar that captures information about the

impact of the sand grains against the wall of the pipe or the choke throat.

Such acoustic methods are normally very sensitive to noise

(changes in WOR, GOR and dynamic noise), and field calibration is mandatory to obtain reasonable results:

• Erosion monitoring on steel goods or special tab erosion: • Ultrasonic gauges are used to clamp to the external

surface of the pipe. They send out an ultrasonic pulse to measure thickness. The method is sensitive to noise from other sources.

• Weight-loss coupons made of the same or similar material as the pipe being monitored are installed and periodically retrieved and weighed. They provide only discrete monitoring and are unsuitable for subsea installations.

• Electrical resistance probes which measure accumulated erosion as an increase of electrical resistance (Ohm’s law) on a known-cross-section. Calibration and temperature changes are of concern.

• Electrochemical probes that determine erosion rate through measurement of the linear polarisation resistance between electrodes through a conductive electrolyte flowing inside the pipe may be used. The method is suitable only for conductive liquids such as water, or oil systems with high water cuts.

Except weight loss coupons, these methods approach real-time if connected to an external computer. From a safety point

of view as well as for production optimization, reducing compounded risk related to poor monitoring reliability is essential in a Sand Management approach. Sand detector data interpretation. Sand detector technology has improved greatly in the recent past, in particular, in improved signal-filtering techniques, rapid acquisition and better analysis. However, the lack of downhole sand monitoring systems introduces errors in terms of the time lag between downhole and surface (or subsea) sand production. To partially compensate for this uncertainty, an analysis approach has been developed. Based on input data such as fluid composition, flow velocities and formation grain size distribution, the theoretical sand transport time may be computed based on a Stoke's law type equation. Grains of different size will have different settlement velocities, so the detected sand signal represents a “smeared out” time trace, as compared to the theoretical response of a downhole sensor. The analysis allows inversion of surface data to compute the theoretical downhole signal on the basis of the surface signal (Figure 6). A slowly decaying signal that may lead to choking back of the well may thus be corrected to show that the event is a sharp, short sand burst, which may lead to more appropriate reaction by the operator. This also helps the post-analysis of the event and the design of a Sand Clean-Up Test. Sand Clean-Up Test. During production start-up, a clean-up period is accounted for. Sand and debris from the damaged zone (due to the explosives of the guns) that has filled or partly filled the perforation tunnels is produced. Also, sand accumulated in the wellbore may be mobilised during this period. However, not all of the damaged zone might be removed at this stage, and parts of it may be produced only during the failure process in the intact part of the formation [13]. Also, part of the sand production induced during the clean-up period may settle in the wellbore and form a stable bed at the given production conditions. This material, or even partly stabilized post-failure zones, may not be removed. This may leave a latent sand production potential, which can be mobilised at a later production stage by the hydrodynamic forces [6, 7]. The trigger may be a period of increased drawdown, formation damage propagation, increased depletion, water breakthrough, etc. The episodic sand clean-up from the post-failure zone may be mistaken for sand produced from a newly created failure zone, and the well will be choked back to prevent further sand production.

Our hypothesis is that much of the sand bursting is sand from the post-failure zone or sand mobilised from the wellbore, and that this sand production will be temporary only. Thus, the production rate should be maintained or increased rather than decreased in order to clean the well properly and avoid future production loss.

In order to be prepared for this, it is suggested that a specially designed Sand Clean-Up Test be performed periodically to clean the well and the near-wellbore region of

6 J. TRONVOLL, M.B. DUSSEAULT, F. SANFILIPPO, F.J. SANTARELLI SPE 71673

accumulated, disaggregated sand. This will allow for better control of the real sand production risk situation, and allow an optimized production rate at all times. Figure 7 shows a typical situation with sand bursts during such a test. Because of the transient and decaying nature of the sand production, it is possible to maintain the increased production rate over time. Figure 8 is a generic diagram showing the great production potential beyond the condition of onset of sand production, which may be obtained through Sand Clean-Up Tests.

Figure 9 and Figure 10 summarise production gains obtained through cleaning of the wells in two North Sea fields. Even if long term production data are not available, the short-term effect is astonishing.

The ultimate sand production limit, where serious sand influx may occur, is impossible to predict with any certainty. Only field experience may provide such an upper boundary. Reaching such a boundary may cause sanding up of the well, expensive cleaning operations for platform wells, and even shutting down of subsea wells. It is suggested, however, that even such a worst-case scenario coupd pay off in the long term due to the value of such data for proper Sand Management in the remaining production wells. Risking one well in a group of 24 wells to achieve a 10% higher oil rate in the remaining 23 wells is clearly of economic merit, and it is likely that the well that was risked can be fully rehabilitated in any case. Well Management Optimization with Sanding Risks With a reliable Sand Management analysis it is possible to define safe limits within which production rates should be kept. This information allows designing and managing the well so as to extend these limits and even to increase well productivity. Some examples are given here below.

Oriented Perforation. Laboratory tests in the past have indicated that the mechanical stability of perforation cavities depends on perforation direction relative to the in situ stress field [33]. This led to the idea of oriented perforating to minimise the shear stresses acting at the wall of the perforation cavities. The method uses 180° phasing, which may affect the perforation density. This is, however, seldom a problem, as weak sandstone formations are normally quite permeable and do not require large drawdowns. Some uncertainty must be accounted for in gun orientation, but computations demonstrate that the sensitivity to this is not very high. Figure 11 shows the large gain, in terms of increased critical drawdown, of proper perforation orientation and the sensitivity of gun orientation. Even at great uncertainties on the order of 20°, benefits are still pronounced. Another argument for 180° phased, orientated perforating is the reduced probability of the perforations being oriented in the worst direction, which by itself reduces the sand production risk.

The method requires a good understanding of the major horizontal stress directions of the reservoir and a proper orientation tool. Such a technique was developed and tested in the Varg field in the North Sea [34] and has also been tried elsewhere [35]. Experience to date is positive, although few field data have been published.

Selective Perforation. In heterogeneous formations, strength variations among different lithologies may be substantial; avoiding perforating the weakest intervals may lead to higher critical drawdown values. Figure 12 shows an example for an HPHT North Sea reservoir, where a major fraction of the pay zone was expected to produce sand at the planned drawdown. The figure shows the cumulative strength of the pay zone along with a computed critical formation strength (below which sanding will occur) for a given drawdown. At a constant drawdown, the entire pay zone is stable until 200 bar depletion is reached, after which sand production may occur. At 400 bar depletion more than half of the pay zone may produce sand. In this case oriented and selective perforations provided sufficient gain in critical drawdown to allow production conditions with sporadic sand bursts only.

Well Productivity Optimization. However, as weak sands often are quite productive, selective perforation is often at the cost of reduced productivity. The extra drawdown obtained may or may not provide a better production rate, and selective perforation must therefore be considered along with production optimisation in an iterative manner.

Productivity Effects of Sand Clean-Up Tests. As already described, the creation of a post-failure zone, removal of the damaged zone and the post-failure zone, and increase of the surface area because of the sand production all stimulate the well and improve the well productivity [36]. Figure 13 shows data from a North Sea production well where such productivity gains are shown in terms of reduced skin values. In most cases the initial skin factor was on the order of +10, but as some sand is produced it is reduced to close to zero or to negative values, as low as –5 in some wells. Field challenges in the Norwegian Sector HPHT and Complex Field Development. In the southern and central part of the North Sea the majority of the reservoirs are located around 2500 m depth, with a normal pressure and temperature regime. The experience from these areas shows that in most cases sand can be managed with only limited use of active sand control. In certain areas in the North Sea and elsewhere on the Norwegian sector, deep reservoirs at 4000 - 5000 m are showing reservoir pressures and temperatures about twice the values common in the North Sea. These fields normally contain gas-condensate and light oil, and are often characterised by heterogeneous formations, multiple pay zones, compartmentalized reservoirs, low formation strength to formation stress ratios, and tight low-permeability zones. Further, for depletion-drive gas and gas condensate reservoirs, depletion values of several hundred bars are expected. Figure 14 shows the results of a sand production onset prediction for such a situation. The range of formation strength is indicated for two reservoirs separated by a thick shale formation. Major problems arise as to the level of vertical communication within each pressure regime as well as the integrity of the inter-reservoir shale. The level of heterogeneity and the large depth make selective perforating difficult. Large drawdown and depletion also impose a risk of interbedded shale

SPE 71673 THE TOOLS OF SAND MANAGEMENT 7

destabilization. Figure 15 shows the critical drawdown as a function of formation strength for the same formations, demonstrating the effect of reservoir heterogeneity and the different pressure regimes. A 150 bar drawdown, which was anticipated in this case, leads to a risk of sand production in the weaker intervals. As the depletion-induced stress changes are uncertain, different stress path scenarios are shown.

The use of long horizontal wells and subsea templates increase the criticality of sand production in these reservoirs. The risk level is also high because the GOR is on the order of 1000 - 2000 in many of these reservoirs, which make facilities erosion a serious safety aspect. From a rock mechanics point of view, a number of challenges are foreseen such as:

• Large depletions leading to serious wellbore stability

problems are expected in the case of in-fill drilling. • Hydraulic fracture stimulation will be extremely

challenging in heterogeneously depleted reservoirs. • Large depletion-induced stresses may lead to casing

collapse or shear. • Heterogeneous depletion may destabilise reservoir

boundaries such as shale layers or faults, resulting in loss of reserves.

• Thick payzones and large depletion may induce reservoir compaction and surface subsidence affecting surface structures.

• Slip or fault reactivation leads to complex stress paths, complicating rock mechanics analysis and long term predictions.

From a sand production point of view, one may note that: • The use of classical sand control equipment might

become problematic, and the question arises as to whether Sand Management will be feasible or not under such challenging conditions.

• Uncertain stress data both in terms of initial stress values and future stress path predictions complicates sand onset prediction and leads to higher uncertainty in the sand production risk assessment.

• Sand monitoring is further complicated by the long transport distances in deep, extended-reach wells.

Marginal field development. New technology gradually allows access to smaller, marginal fields. Extant infrastructure allows economic development, provided well costs are kept low. Sand Management is a low-cost option, and should be suitable for such developments. However, many such fields will likely be developed through remote subsea templates, and re-entry in case of significant sanding problems may thus be prohibited. On the other hand, our experience so far does not indicate a higher well loss frequency than in cases with sand control equipment installed. Rather, the main concern in Sand Management is individual well monitoring and control ability. In many installations sand is registered on the subsea manifold only, which is insufficient for active Sand Management

procedures. Future installations ought therefore to be designed for individual well monitoring and control to optimise the production profile on a single well basis. Subsea separation systems. Due to the increased use of water injection programs, produced water handling has become a central engineering issue. As some operators now tend to produce more water from their fields than hydrocarbons, produced water separation and re-injection has become an alternative to produced water treatment plants. Moreover, in offshore environments, subsea separation and re-injection systems have been developed and piloted. This also means that produced sand will be re-injected into the reservoir or a shallow aquifer. This calls for another set of problems related to sand separation and injectivity. Figure 16 illustrates schematically two principal options for subsea sand separation. Either sand is separated from the oil and stored in a temporary storage tank, or it is directly re-injected. The alternative is to send the sand to the platform with the oil, which is a likely option for oil-wet sand. It should be noted that direct re-injection of sand is, to the authors' knowledge, not been piloted in the field yet. Sand Production in Injectors. Even if water injection does not induce high compressive wellbore stresses, sanding problems and injectivity decline due to sand production have also been experienced in injectors [37]. Different mechanisms have been postulated to explain such phenomena, including water hammer effects due to rapid shut-ins resulting in sand liquefaction, cross-flow between layers during shut-in periods and subsequent re-injection of sand, and unstable intra-reservoir shales. The rock mechanics challenges are many when such problems are encountered, and sand production mechanisms are certainly not the only ones. Mature fields. In the North Sea many fields have passed their plateau production and are experiencing reservoir depletion, increased water and gas cuts, and in certain cases increased sand production. Typically it is reported that onset of sand production is observed at water breakthrough. There is no evidence that water breakthrough is a unique formation failure mechanism [23], but it may play a role in mobilising sand deposited in the perforation tunnels or in the well itself.

This class of problems is also experienced in developing marginal field with short production lives. To some extent, they are also encountered in complex compartmentalised reservoirs, where intra-reservoir leakage between different pressure regimes represents an additional problem. More than ever, the basic principles of Sand Management become critical in these cases, as the gains in squeezing the tail production are substantial. Late-life re-entry and sand control may represent options for severe sanding problems. Net Present Value assessment favors such an option, rather than up-front sand control from day one, because expenses can be delayed and production rates increased during the early life of the field.

8 J. TRONVOLL, M.B. DUSSEAULT, F. SANFILIPPO, F.J. SANTARELLI SPE 71673

Hybrid Completions. In heterogeneous reservoirs, hybrid and eventually staged completion solutions represent genuine options. In some cases a weak productive zone may be produced separately and shut off prior to the production of a more intact, but less productive zone. Complex situations may call for hybrid solutions such as: • Zonal isolation, sliding sleeves and combined perforated

liner/sand control in different zones. • Chemical consolidation, proppant squeeze, frac-packs or

expandable screens in limited zones. • Oriented and selective perforating. • Early life Sand Management and late life sand control.

Many other variations exist, and the approach must be tailored to the individual case. These new approaches are founded on analysis, perfected through experience, and the risk is managed by monitoring and careful engineering. Summary and Conclusions 1. Sand Management has in the past few years challenged

classical sand control techniques in a great number of cases because of its cost-efficiency and ability to maintain high productivity and production rates.

2. The basic physics involved in sand production is to a significant extent understood. However, issues related to volumetric sand production, sand monitoring and horizontal and sub-horizontal sand transport still calls for further R&D.

3. Different tools have been presented allowing analysis of the different life cycle stages of sand production including sand release mechanisms, sand transport, erosion risk of facilities, sand monitoring, sand separation, sand deposition and sand re-injection. There are still a few weak points in the chain, and results of recent and ongoing research need to be implemented practically.

4. Sand Management represents an option for new challenging situations in complex, marginal or HPHT reservoirs. Also, in mature reservoirs, reactivation of sand production is an increasing problem that needs to be dealt with.

SI Metric Conversion Factors Pa × 0.069 × E+05 = psi bar × 0.069 = psi m × 3.2808 = ft Acknowledgements We wish to thank our numerous clients for exposing us to scientifically stimulating and technically complex issues related to sand production problems.

Bibliography 1. Morita, N., Whitfill, D.L., Fedde, O.P., Løvik, T.H.: "Realistic

Sand Production Prediction: Analytical Approach", paper SPE 16990, 62nd Annual Technical Conference and Exhibition of the Society of Petroleum Engineers Proc., Dallas, Tx, Sept. 27 - 30, 1987.

2. Veeken C.A.M., Davies D.R., Kenter C.J. and Kooijman A.P. "Sand production prediction review: Developing an integrated approach". SPE 22792, 1991.

3. Weingarten, J.S., Perkins, T.K.: “Prediction of Sand Production in Gas Wells: Methods and Gulf of Mexico Case Studies”, SPE 24797, Washington, 4-7 October 1992.

4. Sanfilippo F., Brignoli M., Giacca D. and Santarelli F.J. "Sand Production: From Prediction to Management." European Formation Damage Conf. Proc., The Hague, SPE #38185, 1997.

5. Morita, N., Whitfill, D.L., Massie, I., Knudsen, T.W.: "Realistic Sand Production Prediction: Numerical Approach", paper SPE 16989, 62nd Annual Tech. Conf. and Exhibition of the Society of Petroleum Engineers Proc., Dallas, TX, Sept. 27 - 30, 1987.

6. Tronvoll J., Morita N. and Santarelli F.J. ″Perforation cavity stability: Comprehensive laboratory experiments and numerical analysis.″ 67th SPE ATM, Washington DC, SPE 24799, 1992.

7. Tronvoll J. and Fjær E. ″Experimental study of sand production from perforation cavities.″ Int. J. Rock Mech. Min. Sci. & Geomech. Abstr. 31, 393-410, 1994.

8. Santarelli F.J., Tronvoll J.T., Skomedal E. and Bratli R.K., ″The skin factor as a rock mechanics diagnostic tool.″ Proc. SPE/ISRM Eurock′98 Conference, Balkema, SPE #37381, 1998.

9. Dusseault M.B., Geilikman, M.B. and Spanos, T.J.T. ″Mechan-isms of massive sand production in heavy oils.″ Proc 7th UNITAR Int. Conf. Heavy Oils and Tar Sands, Beijing, 1998.

10. Dusseault M.B. and El-Sayed S. ″CHOP – Cold Heavy Oil Production.″ Proceedings 10th European Improved Oil Recovery Symposium, EAGE, Brighton, August, 1999.

11. Geilikman M.B. and Dusseault M.B. ″Fluid-rate enhancement from massive sand production in heavy oil reservoirs,″ J. of Petr. Science & Engineering, 17, 5-18. Special Issue: Near Wellbore Formation Damage and Remediation, 1997.

12. Risnes R., Bratli R.K. and Horsrud, P. ″Sand stress around a wellbore.″ SPE Journal., p. 883ff, 1982.

13. Tronvoll, J., Halleck, P.: The effect of perforation damage on sand production in a weak sandstone. SPE/ISRM 28071, in Proc. EUROCK ‘94, Delft, NL, 29-31 Aug, 1994.

14. Kooijman, A.P., Halleck, P.M., Bree, P. de, Veeken, C.A.M., Kenter, C.J.: "Large-Scale Laboratory Sand Production Test", paper SPE 24798, 67th Annual Fall Technical Conference and Exhibition of the Society of Petroleum Engineers Proc., Washington DC, Oct. 4 - 7, 1992.

15. Kooijman, A.P., Elzen, M.G.A. van der, Veeken, C.A.M.: "Hollow Cylinder Collapse: Measurement of Deformation and Failure in an X-ray CT scanner, Observation of Size Effect", Proc. of 32nd U.S. Symp. on Rock Mech., Norman, July 10-12, 1991 .

16. Halleck, P.M., Damasena, E.: "Sand Production Tests Under Simulated Down Hole Conditions Using Shaped-Charge Perforated Well Cores", paper SPE 19748, 64th Annual Technical Conference and Exhibition of the Society of Petroleum Engineers Proc., pp. 8 - 11, San Antonio, Tx, Oct. 8 - 11, 1989.

SPE 71673 THE TOOLS OF SAND MANAGEMENT 9

17. Kessler N., Wang Y. and Santarelli F.J. ″A simplified pseudo-3D model to evaluate sand production risk in deviated cased holes.″ Proc. 68th SPE Annual Tech. Mtg., v. 2, SPE 26541, 1993.

18. Sanfilippo F., Ripa G., Brignoli M. and Santarelli F.J. ″Economical management of sand production by a methodology validated on an extensive database of field data.″ Proc. 70th SPE Annual Tech. Mtg., Vol. ∆, SPE 30472, 1995.

19. Tronvoll J., Papamichos E., Skjærstein A. and Sanfilippo F. ″Sand production in ultra-weak sandstones: is sand control absolutely necessary?″ 5th Latin American and Caribbean SPE Pet. Eng. Conf., SPE 39042, 1997.

20. Tronvoll, J., Skjærstein, A., Papamichos, E. (1997): “Sand production: Mechanical failure or hydrodynamic erosion”, Int. J. Rock Mech. & Min. Sci. 34:3-4.

21. Charlez, P.A.: “Rock Mechanics - Vol. 2: Petroleum Applications”, Editions Technip, 1st Edition, 1997.

22. Papamichos, E. and Malmanger, E.M.: “A Sand Erosion Model for Volumetric Sand Predictions in a North Sea Reservoir”, paper SPE 54007, 1999.

23. Skjærstein, A., Tronvoll, J.: “Effect of water breakthrough on sand production: Experimental and field evidence” SPE 38806. SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 5-8 October, 1997.

24. Dusseault M.B. and Santarelli F.J. ″A conceptual model for massive solids production in poorly-consolidated sandstones.″ Proc. ISRM Int. Symp. on Rock at Great Depth, eds: Maury V. and Fourmaintreaux D., Balkema, V. 2, pp. 789-797, 1989.

25. Oudeman, P.: “Sand Transport and Deposition in Horizontal Multiphase Trunklines of Subsea Satellite Developments”, SPE 25142, Offshore Techn. Conf. (1993).

26. Shirazi S.A., Mclaury B.S., Shadley J.R. and Rybicki E.F.: ″Generalization of the API RP 14E Guidelines For Erosive Services.″ SPE Ann. Tech. Mtg., SPE #28518, 1994.

27. Shirazi S.A., Shadley J.R., Mclaury B.S. and Rybicki, E.F. ″A procedure to predict solid particle erosion in elbows and tees.″ Proc. Codes and Standards in a Global Environment, ASME-PVP, Vol. 259, pp. 159-167, 1993.

28. McLaury, Wang, J., B.S., Shirazi, S.A., Shadley, J.R., Rybicki, E.F.:: “Solid Particle Erosion in Long Radius Elows and Staight Pipes”, SPE 38842, San Antonio, 5-8 October 1997.

29. McLaury, B.S., Shirazi, S.A.: “Generalization of API RP 14E for Erosive Service in Multiphase Production “, SPE 56812, Houston, 3-6 October 1999.

30. M. M. Salama, "An Alternative to API 14E Erosional Velocity Limits for Sand Laden Fluids"; OTC 8898, Houston, 4-7 May 1998.

31. M. M. Salama, "Sand Production Management"; OTC 8900, Houston, 4-7 May 1998.

32. Bourgoyne, A.T., Louisiana State U., "Experimental Study of Erosion in Diverter Systems Due to Sand Production"; Proc. Society of Petroleum Engineers, Drilling Conference held in New Orleans, 1989.

33. Tronvoll, J., Kessler, N., Morita, N., Fjær, E., Santarelli, F.J. 1993: The Effect of Anisotropic Stress State on the Stability of Perforation Cavities, Int. J. Rock Mech. Min. Sci. & Geomech. Abstr. 30, 1085-1090.

34. Eriksen J.-H., Sanfilippo F., Kvamsdal A.L., George F. and Kleppa E.: ”Oriented Live Well Perforating Technique Provides Innovative Sand Control Method in the North Sea.”, Paper SPE 56472, presented at the SPE Annual Technical Conference & Exhibition held in Houston, U.S.A., 3-5 October, 1999.

35. Morita, N., Boyd, P.A. 1991: "Typical Sand Production Problems: Case Studies and Strategies for Sand Control", paper SPE 22739

66th Annual Technical Conference and Exhibition of the Society of Petroleum Engineers Proc., Dallas, Tx, Oct. 6 - 9.

36. Dusseault, M.B., Tronvoll, J., Sanfilippo, F. and Santarelli, F.J.: "Skin Self-Cleaning in High-Rate Oil Wells Using Sand Management" SPE 58786, 2000 SPE International Symposium on Formation Damage held in Lafayette, Louisiana, 23–24 February 2000.

37. Santarelli F.J., Skomedal E., Markestad P., Berge H. and Nasvig H. ″Sand Production on Water Injectors: Just How Bad Can It Get?″ Proc. SPE/ISRM Conf. EUROCK'98, SPE #41329, 1998.

38. Bratli RK, Dusseault MB, Santarelli, FJ & Tronvoll J 1998. Sand management protocol increases production rate, reduces completion costs. Proc. Trinidad and Tobago Biennial SPE Conf., Port-of-Spain.

10 J. TRONVOLL, M.B. DUSSEAULT, F. SANFILIPPO, F.J. SANTARELLI SPE 71673

Table 1: Critique of different sand prevention methods.

Control Method Major Short-Comings Chemical consolidation • Some permeability reduction

• Placement and reliability issues • Short intervals only

Screens, slotted liners, special filters • Lack of zonal isolation • High placement & workover costs • Longevity of devices • Plugging & screen collapse • Screen erosion • Potential damage during installation

Inside-casing gravel packing • PI reduction • Placement & workovers difficult • High cost of installation • Positive skin development

Open-hole gravel packing • PI reduction • Complexity of operation • Necessity for extensive under-reaming in most cases • Costs of installation

Propped fracturing, including Frac-and-pack, Stress-Frac, and use of resin-coated sand

• Permeability recovery • Risks of tip screen-out during installation • Directional control & tortuosity issues (in inclined wells) • Fracture containment control • Proppant flow-back on production

Selective perforating • Problematic in relatively homogeneous formations • Need for formation strength data • Reduces inflow area

Oriented perforating • Necessity for full stress mapping • Theoretical analysis required • Perforation tool orientation needed • Limited field validation available

Production rate control • Erosion of facilities • Sand monitoring required • Separation & disposal required • Potential for lost production

Table 2: Sanding Impact in Various Environments Environment Bad ??? Good Gas or condensate wells ������ HPHT wells �� Sub-surface wellheads !!!! Depletion drive reservoirs !!! Horizontal wells !! Injection wells !! Separator functioning ! Low PI wells $ Asphalt./scale prec. wells $$ Heavy oil wells $$$$ �� = hazardous; ! = of concern, must be studied; $ = profitable

SPE 71673 THE TOOLS OF SAND MANAGEMENT 11

-100.0 100.0 300.0 500.0 700.0 900.0 1100.0

Critical drawdown [bar]

4830

4850

4870

4890

4910

4930

Log

dept

h [m

RKB

]

No Depletion

300 bar Depletion

600 bar Depletion

Figure 1: Critical drawdown with respect to onset of sand production for an HPHT well on the Norwegian sector.

0

0.5

1

1.5

2

2.5

3

3.5

4

0 20 40 60 80 100 120

Time (hours)

Sandrate(kg/hour)

Results of the modelPublished field data

Figure 2: Predicted and measured sand production in North Sea well. The field data are taken from [22].

3380

3390

3400

3410

3420

3430

3440

34500 2000 4000 6000 8000 10000 12000 14000 16000

Critical diameter (µµm)

Dep

th (

m/M

D/R

KB

)

Flow rate: 2000 m3/dFlow rate: 1500 m3/dFlow rate: 500 m3/d

Figure 3: Sand lifting computation in terms of maximum grain size (critical diameter) to be lifted for a vertical well.

0,0

0,5

1,0

1,5

2,0

2,5

0 500 1000 1500 2000 Grain diameter (µµm)

Ste

ady

velo

city

of

the

gra

ins

(m/s

)

500 m3/day 1500 m3/day 2000 m3/day

5 1/2 " production liner

Figure 4: Sand lifting computation in terms of velocity of the sand grains within a vertical production liner.

12 J. TRONVOLL, M.B. DUSSEAULT, F. SANFILIPPO, F.J. SANTARELLI SPE 71673

0

0.05

0.1

0.15

0.2

0.25

0.3

0.35

0.4

0.45

0.5

0 500 1000 1500 2000 2500 3000 3500 4000

Oil Flow Rate (Sm3/day)

Ero

sio

n R

ate

(mm

/yea

r)

Pipe ID: 3 inPipe ID: 3.5 inPipe ID: 4 inPipe ID: 4.5 inPipe ID: 5 in

Safe limit

Gas Rate: 0 Sm3/dayInternal pressure: 150 bar (>BP)Median grain diameter: 200 micronSand Rate: 36 kg/hour

Oil density: 800 kg/m3

Geometry: Elbow

0

0.05

0.1

0.15

0.2

0.25

0.3

0.35

0.4

0.45

0.5

0 500 1000 1500 2000 2500 3000 3500 4000

Oil Flow Rate (Sm3/day)

Ero

sio

n R

ate

(mm

/yea

r)

Pipe ID: 3 inPipe ID: 3.5 inPipe ID: 4 inPipe ID: 4.5 inPipe ID: 5 in

Safe limit

Gas Rate: 10000 Sm3/dayInternal pressure: 50 bar (<BP)Median grain diameter: 200 micronSand Rate: 36 kg/hour

Oil density: 800 kg/m3

Geometry: Elbow

0

0.05

0.1

0.15

0.2

0.25

0.3

0.35

0.4

0.45

0.5

0 500 1000 1500 2000 2500 3000 3500 4000

Oil Flow Rate (Sm3/day)

Ero

sio

n R

ate

(mm

/yea

r)

Pipe ID: 3 inPipe ID: 3.5 inPipe ID: 4 inPipe ID: 4.5 inPipe ID: 5 in

Safe limit

Gas Rate: 0 Sm3/dayInternal pressure: 150 bar (>BP)Median grain diameter: 200 micronSand Rate: 36 kg/hour

Oil density: 800 kg/m3

Geometry: Elbow

0

0.05

0.1

0.15

0.2

0.25

0.3

0.35

0.4

0.45

0.5

0 500 1000 1500 2000 2500 3000 3500 4000

Oil Flow Rate (Sm3/day)

Ero

sio

n R

ate

(mm

/yea

r)

Pipe ID: 3 inPipe ID: 3.5 inPipe ID: 4 inPipe ID: 4.5 inPipe ID: 5 in

Safe limit

Gas Rate: 10000 Sm3/dayInternal pressure: 50 bar (<BP)Median grain diameter: 200 micronSand Rate: 36 kg/hour

Oil density: 800 kg/m3

Geometry: Elbow

Figure 5: Example of sensitivity analysis performed with a sand erosion model in an oil condensate well: Critical oil flow rate as a function of the internal pipe diameter above and below the bubble point pressure.

dist

ance

alo

ng w

ell a

xis

(Note: the same conceptsapply for horizontal wells)

Q

Z

sanding bed

casing velocityor oil flow rate above perforations

Event atsurface

e.g. 30 second timeinterval, high amplitude

e.g. 15 minute timeinterval, low amplitude

Figure 6: Rationale for inversion principle for converting surface sand detector signals to equivalent downhole signals.

SPE 71673 THE TOOLS OF SAND MANAGEMENT 13

1 2 3 4 5

180

160

140

120

100

80

60

40

20 Time,days

liquid rate m3/hr

wellhead pressure - bar

detectedsand bursts

∆=1300 m3/d

sand-freeflow rate

Rat

e -

m3 /

hr

Figure 7: Sand Clean-Up Test Data from North Sea well.

FlowRate

Sand Strength

Massive sanding

No sanding

Sand bursts

Sand #2Sand #1

Upper limit ofsafe operation

Sand-freelimit line

Productionenhancement

Q1

Q2

Q3

Figure 8: Generic diagram showing the increased production potential obtained through a Sand Clean-Up Test.

0

20

40

60

80

100

120

140

160

180

200

B-7

B-4

0

B-3

B-1

7

B-3

3

B-1

3

B-4

0

B-1

0A

B-4

0

B-3

3

B-2

2

B-8

B-2

3

B-4

0

B-8

B-1

1

B-2

2

B-7

B-2

4

B-5

B-2

7

B-1

6A

Pro

du

ctio

n In

crea

se (

%)

Average Increase of 44 %

Figure 9: Production increase due to Sand Clean-Up Tests in a North Sea field (after [38]).

0

2

4

6

8

10

12

14

16

0 0-20 20-40 40-60 60-80 80-100

100-120

120-140

140-160

160-180

180-200

Percentage Increase

Nu

mb

er (

47 w

ells

) North Sea FieldThree platformsMean increase 36%

Figure 10: Production increase due to Sand Clean-Up Tests in a North Sea field (after [36]).

Norwegian sector HPHT wellVertical well case

0.0

50.0

100.0

150.0

200.0

250.0

300.0

350.0

400.0

450.0

0.0 10.0 20.0 30.0 40.0 50.0 60.0 70.0 80.0 90.0

Perforation direction [deg. Relative to max. horizontal stress direction]]

Cri

tica

l dra

wd

ow

n [

bar

]

600 bar depletion 400 bar depletion

200 bar depletion No depletion

50 bar drawdown line

Figure 11: Effect of oriented perforations on critical drawdown. .

Well: Soutern North Sea200 bar drawdown

0.00

20.00

40.00

60.00

80.00

100.00

120.00

0.00 20.00 40.00 60.00 80.00 100.00 120.00

Accumulated pay [%]

Un

iaxi

al c

om

pre

ssiv

e st

ren

gth

[M

Pa]

Log strengthCritical strength: Zero depletionCritical strength: 600 bar depletionCritical strength: 400 bar depletionCritical strength: 200 bar depletion

Figure 12: Accumulated formation strength profile (log strength)along with critical strength with respect to onset of sand production. Showing the effect of selective perforating.

14 J. TRONVOLL, M.B. DUSSEAULT, F. SANFILIPPO, F.J. SANTARELLI SPE 71673

HPHT well on Norwegian sector Vertical perforations; 600 bar depletion; horizontal well parallel to max horisontal stress

0.0 50.0

100.0 150.0 200.0 250.0 300.0 350.0 400.0 450.0 500.0

0.0 10.0 20.0 30.0 40.0 50.0 60.0 70.0 Formation strength (UCS) [MPa]

Cri

tica

l dra

wd

ow

n [

bar

]

Stress case B Stress case A Base case stresses

Formation A strength range Formation B strength range

150 bar drawdown line

Figure 15: Critical drawdown as function of formation compressive strength for different potential reservoir stress paths in two reservoir compartments separated by a shale layer.

+10

0

-5

MONTHS

SKIN NUMBER

1 2 3 4to

Sand clean-up test

Figure 13: Skin reduction before and after Sand Clean-Up Test in a weak sandstone formation North Sea well (after [8]).

4629

4639

4649

4659

4669

4679

4689

4699

4709

4719

4729

4739

4749

4759

4769

4779

4789

4799

4809

4819

4829

-100.0 0.0 100.0 200.0 300.0 400.0 500.0

Critical drawdown [bar]

Lo

g d

epth

[m

RK

B]

Formation A @ 300 bardepletion

Formation A @ 600 bardepletion

Formation B @ 300 bardepletion

Formation B @ 600 bardepletion

Formation A @ 0 depletion

Formation B @ 0 depletion

Shale

Figure 14: Critical drawdown versus depth for a compartmentalised HPHT reservoir.

SPE 71673 THE TOOLS OF SAND MANAGEMENT 15

Producer

Injector

Monitoring Separation

Temporarystorage

Surfacehandling &

disposal

Direct re-injection

SandCyclone

BatchInjection

Figure 16: Schematic of alternative sand deposition options for a subsea separation system.