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TECHNOLOGY FOCUS

Sand Management and Frac Pack With world population increasing and industrialization demanding newer and harder-to-reach sources of hydrocarbon, the demand for energy is constantly on the rise. Development of hydrocarbons from harsh environments often leads to narrow safe drilling-mud-weight tolerances (or windows) that accompany ultradeepwater subsalt plays and high-pressure/high-temperature developments. These narrow mud-weight windows also can be found in highly compartmentalized developments that encounter severely depleted and/or unconsolidated reservoirs. Technology to tap these reservoirs must meet the growing challenging conditions and produce hydrocarbons both safely and cost effectively. Sand production and fines migration have long held the attention of industry professionals in developing a means to predict them, manage them, and devise innovative ways to avoid or minimize them by use of proper field-development practices and newer downhole completion tools and technologies. Most recently, progress was made in predicting the rates and amounts of sand produced for the purpose of optimizing sand-management strategies and choosing the correct completion/production strategy for the expected sand volumes. Every reservoirrock formation, and corresponding field-development plan, provides a unique set of challenges with associated learning opportunities that may favor one completion method over another. The final decision of which completion method to use lies in an in-depth understanding of the geology, reservoir conditions, in-situ stresses, fluid and rock properties, equipment considerations, sand-management options, and costs. The papers selected for this feature come from varied geographical locations involving different geological settings that highlight the importance of studying the unique conditions at hand, in detail, and applying a fit-for-purpose technology to maximize production and cost effectiveness. Other interesting case and modeling studies, by no means less important, are listed in the additionalJPT reading group.

Mohammed Azeemuddin, SPE, is a Research Scientist—Rock Mechanics, Drilling, and Completions Group, Chevron Energy Technology Company. His 16+ years’ experience includes working on various aspects of geomechanics in the Gulf of Mexico, South America, Australia, the North Sea, the Middle East, Africa, and India. Previously, Azeemuddin worked for Baker Hughes; at King Fahd University of Petroleum and Minerals (KFUPM), Saudi Arabia; and in the field of geotechnical engineering for CH2M Hill. He holds a BS degree in civil engineering from Osmania University, India; an MS degree in geotechnical engineering from KFUPM; and a PhD degree in geological engineering from the University of Oklahoma. Azeemuddin serves on the JPT Editorial Committee and SPE Distinguished Lecturer Committee.

Sand Management and Frac Pack additional reading available at OnePetro: www.onepetro.org SPE 139360 • “A Unique Sand-Control Screen That Enhances Productivity” by G. Woiceshyn, Absolute Completion Technologies, et al. SPE 143941 • “Formation Loading and Deformation of Expandable Sand Screens” by Colin Jones, Weatherford, et al. SPE 144047 • “Controlled Use of Downhole Calcium Carbonate Scaling for Sand Control: Laboratory and Field Results, Gullfaks” by N. Fleming, SPE, Statoil ASA, et al.

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SAND MANAGEMENT AND FRAC PACK

Deg Multistage Frac Packs in a Lower Tertiary Formation—Cascade and Chinook Fields Offshore frac-pack operational limitations include service-tool erosion, overall fracture-treatment-vessel capacity, boat-to-boat fluid transfers, and crew fatigue. Geological complexities were another major challenge in completing this very thick interval. Perforation intervals had to be placed in a manner to avoid a fault (and thus a potential early screenout), to avoid a water , and to comply with tool-spacing limitations, while maximizing with net pay. A specific approach was developed to design the fracture-stimulations for a Lower Tertiary formation in the Cascade and Chinook fields.

Introduction The Cascade and Chinook fields are 250 miles south of New Orleans in the Gulf of Mexico (GOM) in ultradeepwater depths between 8,200 and 8,900 ft. The oil-producing reservoir is in the Lower Tertiary Wilcox formation, with a gross sand thickness of 1,200 ft. The reservoir midpoint is at an average depth of 25,600 ft true vertical depth (TVD) with a bottomhole pressure of 19,500 psi and a bottomhole temperature of 260°F. The reservoir comprises vertically stacked thin beds of sand and fine-grainedsiltstone intervals with no effective vertical permeability. This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 140498, “Challenges of Deg Multistage Frac Packs in the Lower Tertiary Formation—Cascade and Chinook Fields,” by Ziad Haddad, SPE, FOI Technologies; Mike Smith, SPE, NSI Technologies; and Flavio Dias De Moraes, SPE, Petrobras, prepared for the 2011 SPE Hydraulic Fracturing Technology Conference and Exhibition, The Woodlands, Texas, 24–26 January. The paper has not been peer reviewed.

It was recognized early on that dealing with the Lower Tertiary formation required a change in focus from a soft-rock frac-pack completion to a hard-rock hydraulic-fracturing completion, similar to those used in the Wilcox formation in south Texas. The secondary objective was to design a sand-control completion to retain the proppant pack and eliminate proppant flowback in screenless hard-rock fracturing completions. To outline a basis of design for future Cascade and Chinook hydraulic-fracturing treatments, the initial planning phase was to develop a complete and comprehensive set of fracture-treatment-design data to be used in developing the preliminary treatment designs and evaluating the material-selection options, and to identify key questions for future wellsite data collection and execution. The full-length paper details this outline. Design Challenges The first well completed in the Cascade field was completed with three proppedfracture treatments in the upper and lower Wilcox zones. The challenge was to complete this very thick interval while avoiding fracturing the oil/water and avoiding placing perforations too near the fault at 25,832 ft measured depth (MD). Completion Hardware A single-trip multiple-zone (STMZ) sand-control completion system was selected for the Cascade and Chinook project. The STMZ system is not new. It has been used successfully in much shallower completions (less than 15,000 ft) and with much lower bottomhole pressures. This was the first use of STMZ technology at these depths, pressures, and operating conditions. Reservoir modeling

indicated that hydraulic fracturing would be required to produce the wells at economical rates. Given the overall gross thickness of the reservoir (>1,200 ft), each well would require multiple-stage fractures to stimulate the entire reservoir effectively. Conventional stacked frac packs were considered initially because of the extensive industry experience with this type of technology in the GOM. However, it was anticipated that the treatment would require 30 days and eight roundtrips to install a conventional three-zone stacked frac pack compared with 14 days and three roundtrips for a five-zone STMZ system. Ultimately, an STMZ system was selected as the primary sand-control completion system. Perforation Designs The perforating philosophy also required a change. The strategy for soft-rock formations was to perforate all the net pay. With the new design, limited perforated intervals would be considered as a means to initiate a fracture and take advantage of in-situ stresses to achieve the optimum fracture geometry and to all the pay intervals. Fracture-Treatment Design The basis for design developed for the Cascade exploration well (including use of high-viscosity crosslinked gel to combat fluid loss in the Wilcox and the use of bauxite proppant) was used to develop preliminary treatment designs, and then to compare options (e.g., higher/lower rate, three vs. four fracturing treatments). First, a trial perforated interval was selected and basic fracture geometry was studied by simulating simple gel injections (by use of a gridded, planar 3D-fracture simulator).

For a limited time, the full-length paper is available free to SPE at www.jptonline.org. JPT • OCTOBER 2011

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For the actual design, a rate of 25 bbl/min was selected. The pump schedule then was planned for a tip screenout (TSO) to occur after pumping 750 to 1,000 bbl, with fracture penetration of approximately 200 ft. Additional slurry then would be pumped into the fracture to increase its width. To achieve this, 22% efficiency was used to define a first approximate schedule. This design gave a pad fraction of 67% (measured from the start of pumping pad to the start of the TSO). This first approximate schedule then was modified to provide the best proppant coverage. This process was repeated for two cases. The first case included three fracture-treatment stages, and the second included four stages. Post-treatment production then was simulated with a 3D reservoir model to honor the actual geologic layering. The results normalized productivity index (PI), with the base case being a gravel-pack completion of the entire net pay with zero mechanical skin. The normalized PI

for the two cases showed that adequate formation coverage could be achieved with three fractures. Pretreatment Analysis Pretreatment testing for all fracturing treatments consisted of a gel minifracture treatment, followed by a step-rate injection test. The crosslinked fluid would be circulated to the crossover tool, the tool would be shifted, and the minifracture treatment would be conducted by bullheading the viscous gel into the formation while displacing the tubing with slickwater. After a suitable shut-in time, the step-rate test was pumped. Closure Pressure. In this case, the fracture was propagating at a pump rate of 5 bbl/min at an injection pressure of 21,869 psi. The intersection between before/after fracture propagation is defined as the fractureextension pressure (Pext): in this case, 21,780 psi at 2.8 bbl/min (0.86 psi/ft). Height-recession behavior is created

by the following sequence of events. First, the fracture initiates and propagates into the lower-stress pay. At this point, pressure must be greater than Pext. As the fracture grows in length, net pressure increases and the fracture may propagate up/down into adjacent higher-stress, lower-fluid-loss layers (i.e., the over-/underlying shale). When pumping stops, these higherstress zones close first, forcing fluid back into the main part of the fracture. This flowback causes a relatively slow rate of pressure decline immediately after shut-in. However, for this case, this pattern was surprising because radial fracture geometry was expected (i.e., minimal height confinement). Fracture Geometry. Analysis showed that the unexpected height-confinement behavior was caused by tectonic compression on the “hard streaks” (heavily calcite-cemented sands) in the formation. Minimum in-situ stress was expected to be approximately 19,500 psi, but measured

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Post-Treatment Analysis Post-treatment analysis included netpressure history matching, radioactive tracer logs (i.e., to determine if long 200-ft perforated intervals can be stimulated/packed), and temperature trends from bottomhole memory gauges. Post-treatment bottomholepressure data were used to review the treatment following the pretreatmenttest analysis. The post-treatment simulation used the same geomechanical model (including stress, modulus, and fluid loss) that was used for the minifracture-treatment interpretation. Given the uncertainties created by a 15-minute shut-in (mechanical problems), bottomhole treating pressure was nearly exactly equal to design predictions. With 8 lbm/gal of proppant on the perforations, a total, instant screenout occurred. This same behavior occurred on a previous treatment. With no bottomhole-pressure data, there was considerable uncertainty regarding what caused the abrupt wellbore screenout. The instantaneous-screenout behavior suggested downhole-tool problems. However, the treatment was pumped above overburden pressure; thus, a secondary fracture may have formed, causing total dehydration of the slurry

near the well. In any case, the treatment was deliberately made less aggressive in of increasing pad volume and deg for a smaller net-pressure gain (i.e., reduced conductivity with slightly greater penetration). The final geometry ed for the effects of the hard streaks. For this stage, high stresses in the hard streaks caused compressive tectonics and made it difficult to treat the thin sand (25,480–25,500 ft TVD) regardless of perforation placement or job size. For many other cases, the problems caused by these hard high-stress layers could be alleviated by straddling these layers with the perforations. While the net-pressure analysis ed the idea of a simple geometry, injection pressure being greater than the estimated weight of the overburden was still a concern. This was alleviated with additional data. A radioactive-tracer scan was collected when pulling the bottomhole assembly. It showed proppant coverage over the entire perforated interval, implying a vertical fracture. Bottomhole-temperature-vs.-time analysis showed continuous flow past the gauge throughout the treatment. Unfortunately, for the STMZtool configuration, the temperature/ pressure gauge is always above the top of the perforation in the blank pipe. Therefore, these data offered no information about downhole flow over the perforated interval. The recorded temperature did confirm much more downhole cooling than predicted. Possibly, this caused more tool movement than expected, which led to the total screenouts. Additional work is under way to understand the true nature of these screenouts better. Subsequently, bottomhole-pressure data and tool examination showed that the service tool could have moved out of position, causing the two total screenouts. Changes in procedures allowed the next treatment to be pumped to completion, again with very good agreement between predicted and measured pressure throughout. JPT

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stress was more than 2,000 psi higher. Postulating a tectonic strain of 0.002, to increase stress in the Wilcox sand to the measured level, created very high confining stress in the hard streaks. This resulted in the increasing netpressure trends. The revised stress profile was used to history match the minifracture treatment. The hard streaks, caused by tectonic compression, did create height confinement. Later, this confinement compromised the fracture treatment slightly, limiting fracture penetration in the Wilcox sand above 25,300 ft TVD and below 25,480 ft TVD. For a later well, special care was taken in the planning to ensure that it was not necessary to fracture through a hard streak to all of the target pay.

SAND MANAGEMENT AND FRAC PACK

Reducing Fines Migration by Use of Nanofluids Injection—An Experimental Study Formation damage because of fines migration is a major reason for productivity decline. Many studies have characterized fines and their migration effect on permeability reduction. Nanofluids that contain nanoparticles (NPs) show specific properties including a high tendency for adsorption and being a good candidate for injection into the near-wellbore region because of the very small NP sizes. The study indicates that fines could adhere to the matrix grains, hindering their migration, when the porous materials are soaked with nanofluids.

Introduction Fines are loose unconsolidated particles (smaller than 37 µm) that move with fluid flow and cause formation damage because of the filtering action of the porous media. The biggest drawbacks of this process are pore plugging and productivity-index reduction. Various surface forces have been found to be responsible for fines detachment and release from the pore surfaces. London/van der Waals attraction, double-layer and Born repulsion, and hydrodynamic forces are the dominant forces in the detachment of fines from porous media. When the total interaction energy between fines and pore surface becomes positive, the repulsive forces are bigger than attractive forces and fines detachment occurs. This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 144196, “Reduction of Fines Migration by Nanofluids Injection—An Experimental Study,” by A. Habibi, SPE, M. Ahmadi, and P. Pourafshary, SPE, University of Tehran, and Sh. Ayatollahi, SPE, Shiraz University, prepared for the 2011 SPE European Formation Damage Conference, Noordwijk, The Netherlands, 7–10 June. The paper has not been peer reviewed.

NP size ranges from 1 to 100 nm, and NPs have high specific surface area and unique properties, such as very high adsorption potential and heat conductivity. NPs have been used for formation-damage control, enhancing oil recovery, and wettability alteration. In the proppant packs, NPs strengthened the attractive forces and fixed the suspended fines in the porous media. In this experimental study, porous media were soaked with nanofluid for 24 hours and then the suspended fines were ed through porous media to determine the most efficient component. In the next step, a glass-bead-packed column containing uniformly distributed fines in the bed was flooded with distilled water. To investigate the main parameters in this process, the NP concentration and fluid-injection rate were investigated. The zeta potential of the treated models was measured, and the total interaction energy was calculated to the results. Finally, scanning-electronmicroscope (SEM) images of the surface were obtained for qualitative observation of fines attachment to the pore surfaces. Experimental Work In this experiment, the fines size was 1 µm. Two types of tests were performed to assess the effects of the proposed NPs for fines fixation. In the first set of experiments, a synthetic porous medium was used with different types of NPs in the soaking fluid to study the effect of matrix soaking on fines fixation. Fines suspension (i.e., fines particles+distilled water) was injected from the top of the packed column and was flowed through the packed bed by gravity. Effluent was collected and ed through filter paper to measure the adsorption efficiency of different NPs. In this work, the glass beads were soaked for 24 hours in the nanofluid without any calcination process.

In the second set of tests, a synthetic bead-packed core was used. Glass beads and 10 g of formation fines were mixed to create a uniform core structure. To prepare the core, a sleeve (1.5-in. diameter×1-ft length) was filled with 30/40-mesh glass beads mixed with fines. This synthetic porous medium then was fitted into the core holder. After 3 hours under vacuum, the porous medium was saturated with nanofluid and distilled water was used as the reference test. The medium was soaked with the nanofluid for 24 hours; then, distilled water was injected to produce the formation fines in the medium. Effluent samples were collected for spectroscopy analysis to determine the process efficiency. Results First Set of Tests (NP Selection). Four tests were designed to investigate the effect of the types of NPs for fines fixation compared with nontreated medium. In each test, except the reference test, the packed bed was soaked with a nanofluid, and then the fines suspension was ed through the column. Nanofluids with 0.1 wt% of NPs were used. The results verified that MgO NPs were the best adsorbent for fines fixation. SEM results for the glass-beads surface soaked with MgO NPs are presented in the Figs. 1, 2, and 3. Figs. 1 and 2 show the adsorbed fines and glass-bead surface, while Fig. 3 shows the MgO NPs on the glass surface. This qualitative observation showed that the main difference in adsorption efficiency between the reference state and MgO-soaked medium was the presence of MgO NPs on the glass-bead surfaces. Increasing the surface area and changing the surface forces were the main roles in remediation of fines migration in the treated medium with MgO.

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Fig. 1—Glass beads soaked in MgO nanofluid.

Fig. 2—Adsorbed fines on the glass-bead surface.

Fig. 3—Closer view of adsorbed fines and MgO NPs on the glassbead surface.

Bead-Packed Flooding (Second Test). Fines migration in the porous medium is affected by fluid-flow hydrodynamics, although nanofluid concentration is regarded as an important parameter, both technically and economically. Several tests were designed to study the effect of MgO NP concentration and fluid-flow rate on the reduction of fines migration in a glass-bead-packed core. The model was prepared to mimic fluid flow and fines in the formation. From the experimental design used for this study, concentrations of MgO NPs and injection rate were investigated at three levels. Nine tests, in addition to the reference case, were

performed. In the reference case, the vacuumed porous model was saturated with distilled water. In the other tests, it was saturated with nanofluids at different concentrations. Calibrated spectrophotometer analysis was used to investigate the concentration of fines in the effluent samples. NP Concentration. The results indicated that as the zeta potential of the surface increased positively, it affected the attraction and repulsion forces to increase the efficiency of the finesremediation process. When the porous medium was soaked with MgO NPs for 24 hours, MgO NPs would fix the fines on the surface. As zeta-potential values

changed from −34 to +14.2, doublelayer repulsion is reduced; thus, the total interaction energy had the effect of more attraction. The results showed that any increase in NP concentration led to fines-migration reduction. Also, the hydrodynamics effect of the fluid in a porous medium represents a critical velocity for fines detachment from the surfaces because the measured effluent-fines concentrations for 1000- and 1300-mL/h fluid rate were equal. Injection Rate. One of the important repulsive forces for fines release in porous media is the hydrodynamic force, releasing the fines mechanically.

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To investigate the effects of fluid rate, nine pore volumes of fluid was injected through the models at three different velocities. Often, fluid flows in the porous medium in laminar flow; thus, three injection rates were selected in the laminar region having Reynolds number less than unity. The amount of fines in the exit stream of the coreflooding system did not change at velocities greater than 1000 mL/h. At 0.2 wt% NP concentration, the attraction forces between the pore surfaces and the fines were high enough to hold the fines in place, even at very high fluid rates. Total Interaction Energy Surface potential was calculated for different fluid-flow velocities. It was shown that the dimensionless total interaction energy at separation distances less than 1 nm was strong repulsion (positive) because of Born repulsion. The total energy for the reference case changed considerably compared with the NP-treated cases at distances of more than 2 nm, mostly because of double-layer-repulsion forces. Therefore, the total energy becomes positive at distances greater than 2 nm and causes the fines to detach from the silica surface. A small difference between the cases treated with NPs was noticed because of differences in zeta potential and double-layer repulsion. To study the effect of injection rate on dimensionless total interaction energy, the calculated total energy was studied for the 0.05 wt% NP concentration and different velocities. Hydrodynamic potential depends on fines sizes and fluid velocity. Hydrodynamic potential can be neglected because it is important only at high velocity and with large particles. Because Born repulsion can be neglected at distances greater than 1 nm and hydrodynamic potential can be neglected when compared with double-layer repulsion and London/ van der Waals potentials, the distance between fines and the surface increases and hydrodynamic potential increases (however, it can be neglected when it is compared with other forces involved). It must be mentioned that, in this condition (small particles and low velocity), hydrodynamic potential can be neglected. The main differences between the reference test and the others were the surface zeta potential and double-layer repulsion. Conclusions Three types of adsorbent NPs were selected to examine their abilities to prevent fines migration in porous media. The MgO NP was selected as the best remediation agent. The effects of MgO NP concentration and fluid velocity on the reduction of fines migration in porous media were studied. The optimum NP concentration for soaking the porous medium and the critical fluid rate were found to be 0.2 wt% of NP and 1000 mL/h, respectively. It also was noticed that at a fluid rate higher than the critical value, fines migration did not occur. The results showed that the use of 0.2 wt% of NPs would reduce fines migration considerably. The calculation of dimensionless total interaction energy between fines and surfaces confirmed the experimental result. At 0.2 wt% NP concentration, the total interaction energy remained more negative compared with other NP concentrations. Qualitative SEM observations clearly showed the adsorbed fines on the JPT treated solid surfaces.

JPT • OCTOBER 2011

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SAND MANAGEMENT AND FRAC PACK

Selecting a Completion Strategy for Sand Control and Optimal Production Rate—Unayzah Sandstone Reservoir For field development, it is important to identify reservoir structure, heterogeneity, rock properties, and fluid characteristics to select an optimal development strategy for enhancing production and increasing recovery in a cost-effective manner. Therefore, a detailed reservoir description and characterization is required by use of geophysical, geological, and engineering data. This condensate-rich, high-flowcapacity, and highly sanding deep gas reservoir was developed gradually and optimized to select the most appropriate drilling-and-completion technique.

Introduction Saudi Aramco’s SA-1 field produces from the Permian Unayzah formation. The first well drilled penetrated the Unayzah-A zone in 1997 and showed excellent reservoir quality. Cores were collected from the well and, subsequently, from other wells confirming unconsolidated reservoir rock with low Young’s modulus and compressive-strength values. To avoid sanding during production, early wells in this field were completed as vertical wellbores with frac-pack stimulation using screens, even though difficulties were encountered during frac-pack installation. With technology advances in drilling and completion, the development method This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 131078, “Selection of Completion Strategy for Sand Control and Optimal Production Rate—Field Examples From Saudi Arabia’s Unayzah Sandstone Reservoir,” by Zillur Rahim, SPE, Bandar Al-Malki, SPE, and Adnan Al-Kanaan, Saudi Aramco, prepared for the 2010 SPE Asia Pacific Oil & Gas Conference and Exhibition, Brisbane, Australia, 18–20 October. The paper has not been peer reviewed.

shifted to drilling horizontal and highly slanted holes. This method eliminated deploying the frac-pack system, increased reservoir substantially, and improved well performance. To protect well integrity and eliminate sand production, expandable sand screens (ESSs) were used for completing the wells. Higher sustained gas rates were achieved with a reduced non-Darcy skin, sanding was eliminated, and risks related to deployment of the completion equipment (ESS) were reduced. Risks Completing wells in high-sanding environments raises major risks not faced in more-competent formations. In most cases, the following risks and the costs associated with remedial actions are significant in deep high-temperature regions. • Loss of well integrity or productivity after selecting a nonoptimal completion technique • Loss of integrity downhole or at the surface because of persistent sand production • Production or reserves losses resulting from the inability to recover damaged wells • Buildup of scale and screen-plugging materials that reduce productivity • Deterioration of screens caused by corrosion and erosion Frac-pack installations have been used widely to prevent sand production. Such installations are suited for laminated sands or stacked-pay sections that require a combination of stimulation and sand control. For improved productivity and greater reservoir , drilling horizontal or slanted wells and then completing them with sand screens is an effective option. The ESS application enables selective completion and production from multiple intervals and reduces the inefficiency and risks asso-

ciated with frac-pack completions that require careful consideration of pumping and proppant-handling issues. The inflow performance of high-rate gas wells often is controlled by turbulentflow effects in the near-wellbore region. These effects result in large non-Darcy skin factors, especially in frac-pack or gravel-pack wells, which can reduce well productivity substantially. Use of ESSs eliminates the gravel-pack region around the screen in the annulus, resulting in larger wellbore diameter and an improved production rate. The drivers to use the ESS completion were as follows. • Reduces logistics and risks during installation phase—no need to change the mud system • Provides operational flexibility and reduced cost • Eliminates the need for multistage cased-hole proppant completion • Improves sand control, maintains well integrity, and stabilizes and s the borehole • Achieves maximum reservoir by drilling slanted wells yielding improved flow rate • Isolates intervals as needed and sets the completion above the gas/water (GWC) to delay water-coning effects • Reduces turbulent flow, thereby reducing the non-Darcy flow effect • Increases hole size because no annular space exists, providing a large open area allowing higher production rates In Saudi Aramco’s SA-1 field, the completion strategy was changed from frac pack to ESS for many of the preceeding reasons, especially improved recovery. Wells that were completed initially with frac packs are being sidetracked and converted to the ESScompletion system. Rock Strength Rock strength is influenced by physical and elastic properties of the rock.

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Well logs, such as sonic and density, and core tests are used to assess rock strength. Rock strength and dynamic modeling of geomechanical properties dictate whether sanding will occur during the well’s life. Sanding must be identified, quantified, and reduced or eliminated to achieve optimal gas production. Major sand-control mechanisms include mechanical retention systems (sand screens), plastic consolidation (resins and epoxies), oriented perforations (toward maximum-stress direction), and use of frac-pack or gravel-pack systems. Geomechanical Correlations Rock strength is the most critical factor in determining the sanding tendency of a formation. Rock-strength properties depend largely on bonding type and quality of the solid particles (i.e., solid bonds in igneous rocks, cementation for consolidated sediments, cohesion for clay, and friction for cohesionless unconsolidated sediments such as sand and gravel) and on internal structure of the matrix rock. In addition, strength depends on porosity and fluid content. To design an effective sand-control

completion, rigorous characterization and modeling were performed on the Unayzah-A reservoir. Rock-mechanical properties, such as Young’s modulus, Poisson’s ratio, and unconfined compressive strength were correlated with reservoir porosity and openholelog data. The sand consolidation was observed on the sonic shear and compressional travel-velocity graph. ESS Deployment ESS is a specialty sand screen that is designed to be expanded inside the wellbore to fit the wellbore diameter. The ESS comprises three simple elements: expandable base pipe, filtration media, and expandable protective shroud. The base pipe is an expandable slotted tube that can be expanded by up to 60% of its diameter and provides a large inflow area for the produced fluids. Typically, inflow areas for expandable base pipe are 30 to 60% depending on the expanded diameter of the ESS. The protective shroud ensures that the filter media is not damaged while running the completion. The increase of the system’s internal diameter after the expansion results in improved productivity.

Strategies for Sand Control On the basis of core testing and calibration of geomechanical properties with field data, Saudi Aramco developed a comprehensive sand-prediction model to estimate reservoir mechanical properties and the safe drawdown pressure for any given formation and field. Because of the nonlinear nature of sanding, field measurements to quantify the amount of sand produced as a function of gas rate and pressures are important calibration coefficients that were integrated in the model. Depending on the sanding tendency and intensity, different techniques are adopted for development and production of deep unconsolidated gas reservoirs to obtain a high sand-free rate. The method adopted for the SA-1 field was to drill horizontal or highly slanted wells to achieve maximum reservoir , maintain at least 50-ft-truevertical-depth standoff from the regional GWC level, and complete the well with an ESS system. The screen size, mesh, and quality are preselected on the basis of complete sieve and geomechanical analysis of formation sand to ensure sand prevention, high gas flow,

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and screen integrity during the productive life of the field. SA-1 Field ESS Completion: Case Study With the drilling-and-completion strategy adopted for the SA-1 field, a well is drilled first as a vertical pilot hole. This vertical hole helps assess reservoir quality and identify a GWC. Then, on the basis of seismic-impedance maps and neighboring-well information, a sidetrack is initiated in the direction of good porosity development. The inclination of the well is maintained between 40 and 50°, and the total depth of the well is kept much above the GWC (either the regional GWC value or the GWC obtained from the pilothole terpretation). At the time of writing this paper, the SA-1 field was producing 20 to 30 MMscf/D. With a high condensate level in this field (>400 bbl/MMscf), wells have experienced a low-to-moderate decline, with reservoir pressure declining steadily and within expected limits. Improved reservoir from horizontal wells has decreased the pressure drop near the wellbore, decreased

JPT • OCTOBER 2011

the rate of condensate dropout, and improved overall well potential and reservoir performance. Early wells drilled as vertical wells that experience excessive production decline resulting from deteriorated frac-pack screen and proppant conductivity are being sidetracked and completed with an ESS system. Conclusions Several methods were tested to optimize gas production in a deep sandproducing-prone gas environment. Frac-pack technology was implemented initially and worked reasonably well, but to mitigate risks in frac-packsystem installation and to adapt to variations in reservoir parameters over time (e.g., declining reservoir pressure and increasing condensate dropout), drilling horizontal or slanted wells and completing them with ESSs became the preferred application. Several wells have been completed with ESSs, and production-data analyses indicate well stability, enhanced rate, and sustained performance. The following conclusions were derived from experiences with laboratory analyses, building a geomechanical model, selecting the

ESS type, and implementing the technology in the field. • A comprehensive assessment of formation properties by use of geological, reservoir, and geomechanical data is required for optimized field development. • The sanding problem can be handled best with a downhole-completion system. • Frac pack is a viable sand-control mechanism if zonal isolation, avoiding the GWC, and non-Darcy skin are not concerns; however, non-Darcy-flow skin factor can reduce the well rate significantly. • Drilling horizontal or slanted wells and installing ESSs in the Unayzah-A reservoir proved to be an excellent technology for sand control, production optimization, and achieving longterm sustained rates. • An ESS offers well integrity, negligible skin damage, and reduced nonDarcy-flow effects. • Slanted and horizontal wells maximize reservoir and can be completed only with sand screens in this field. Therefore, use of an ESS in such wells is the only viable option. JPT

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