Unconsolidated Reservoirs Research Articles

Next-Generation Expandable-Completion Systems

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 97281, "Next-Generation Expandable-Completion Systems," by Gareth Innes, SPE, Quentin Morgan, SPE, Ally Macarthur, SPE, and Annabel Green, SPE, Weatherford, prepared for the 2005 SPE/IADC Middle East Drilling Technology Conference and Exhibition, Dubai, UAE, 12–14 September. In many cases, openhole completions could provide maximum well productivity. However, use of the method has been impeded by the inability to achieve effective zonal isolation. An expandable completion that combines slotted- and solid-expandable technology and uses conventional unexpanded premium connections can deliver freely configurable completion architecture. Introduction Expandable sand screens provide direct contact of the screen with the formation as a means of reducing completion skin and improving sand-retention characteristics. The base technology is being integrated with new and conventional downhole technologies to enable multizone completions. A common conventional approach used to complete and commingle multizone unconsolidated reservoirs has been to, first, set and cement casing in the wellbore to isolate zones. The zones of interest then would be perforated before installation of a screen and placing gravel to control solids migration. This cased-hole sand-control technique has worked reasonably well but has a history of high completion skins. Also, the resulting smaller inside diameter makes the subsequent design and installation of selective-production upper-completion strings difficult, limiting the overall achievable functionality. In many cases, emulating an openhole high-deviation or horizontal completion strategy can increase well productivity. To enable these productivity gains and facilitate selective production handling, zonal-isolation technologies were combined with compliantly expanded screens to create a sandface completion with cased-hole functionality. Zonal-isolation technologies that satisfy functionality and expandable performance criteria include swelling elastomers and solid expandables. Expandable-Completion Development An expandable screen comprises three sandwiched layers: the base pipe, filter media, and outer protective shroud. The base pipe is slotted, as is the outer shroud. These slots open during expansion to accommodate the change in diameter, while overlapped layers of filter media slide across each other to maintain sand-retention integrity. The use of slots allows expansion ratios up to 80% greater than the original diameter. The entire length of the original design was expanded, including the connectors. The original expandable screen was designed for use in single-zone openhole applications. Large exposed filter area and variable borehole contact (known as compliant expansion) provide gravel-pack functionality. The design premise was that a compliantly expanded filter that could eliminate as much of the annular gap as practicable would promote rapid formation stabilization and minimize the movement of sand particles around the screen during the transient sand-production period. The large, directly exposed filter surface was designed to minimize pressure drops in the screen and sandpack composite caused by mud particles and formation fines.

Seismic time-lapse effects and stress changes: Examples from a compacting reservoir

Compaction of unconsolidated reservoir rock represents a major drive mechanism in many oil and gas reservoirs. Significant volumes of produced hydrocarbons may be credited to this effect. However, compaction might also result in surface subsidence, a dynamic overburden, and local permeability losses in the reservoir.

Overview: Offshore Completions (August 2005)

Last year, in this space, I commented on innovations being implemented on recent offshore completion projects and how offshore completion practices have undergone major changes. Our industry, regarding offshore developments, apparently has an unlimited ability to amaze the world with new advances. Projects that were considered not feasible 5 years ago now are being implemented. Driven by various reasons, including depletion of conventional reserves and increasing oil prices, oil and gas production in deep water became customary in many regions around the world, and it was not a surprise that, during the 2005 Offshore Technology Conference, oil companies started to reveal plans aiming at production of fields under 3000 m of water. Use of intelligent-well completions is spreading globally, not only for large deepwater projects, but also for small offshore discoveries where its use in subsea satellite wells may bring profitability to an otherwise uneconomical project. Smart systems, with remotely operated valves, allow operators to control various producing zones, shutting down those not responding as expected without expensive well interventions. All of that can be achieved while data for each independent zone are simultaneously acquired and recorded. Developing fields that present complex geology and deep reservoirs that have high pressures and temperatures still present challenges for the industry, mainly when unconventional-trajectory wells are used. Some of the issues being investigated involve completion of long horizontal sections in unconsolidated reservoirs; flow assurance, mainly for deepwater conditions; and subsea processing, including gas compression and gas/liquid and oil/water separation. Some of these challenges are addressed well in the papers featured in this issue. Available from the SPE eLibrary: www.spe.org SPE 90552 - “Gravel Packing Deepwater Long Horizontal Wells Under Low Fracture Gradient,” by Chen, Zhongming, SPE, BJ Services, et al. Available from the OTC Library: www.otcnet.org OTC 17399 - “Subsea Gas Compression—Challenges and Solutions,” by Fantoft, R., FMC Kongsberg Subsea A/S OTC 17397 - “Hybrid Riser Towers From an Operator’s Perspective,” by Sworn, A., BP plc

3-D Model Studies of Alkaline Flooding Using Horizontal Wells

In this study, the effect of sodium hydroxide (NaOH) solution for the improved oil recovery of Garzan (26° API) crude oil was investigated using two different laboratory models. The effect of injection rate on oil recovery was investigated using a one-dimensional unconsolidated limestone reservoir model. The effect of horizontal and vertical well configurations on oil recovery was also studied using a 3-D physical model and various well configurations. As previously studied, the interfacial tension measurement of Garzan crude oil and NaOH solution interface was measured to find the optimum concentration of the alkaline solution that gave the minimum interfacial tension at the crude oil/alkaline solution interface at different salinity of the alkaline solutions. The results of the 1-D model tests showed that the NaOH solutions with increasing salinity has given the most significant incremental oil recovery, about 3 to 9% for Garzan crude oil. The results of the displacement tests showed that the injection flow rate of alkaline solution has an important effect on Garzan crude oil in spite of oil recovery achieved. The optimum injection flow rate for Garzan crude oil has been found as 183 cc/hr. A total of 6 runs were conducted to investigate the effect of horizontal-vertical well configuration on oil recovery by alkaline flooding. Alkaline flooding experiments were performed in three different well configurations: (1) a vertical injector and horizontal producer, (2) horizontal injector and horizontal producer, and (3) a vertical injector and vertical producer. The highest oil recovery was obtained through vertical injector-horizontal producer configuration.

Viscous deformation of unconsolidated reservoir sands—Part 1: Time‐dependent deformation, frequency dispersion, and attenuation

Laboratory experiments on dry, unconsolidated reservoir sands from the Wilmington field, California, reveal significant viscous creep strain under a variety of loading conditions. In hydrostatic compression tests, following initial loading to 10 MPa, the creep strain that accompanies 5‐MPa loading steps to 15, 20, 25, and 30 MPa exceeds the magnitude of the instantaneous strain (∼3 × 10−3). We observed a two‐fold increase in bulk modulus with frequency over the range of frequencies tested (10−6to 10−2Hz), which is consistent with a viscoelastic rheology of unconsolidated sand. The data demonstrate that the effective static bulk modulus is approximately one‐third of that at seismic frequencies. By measuring the phase lag between stress and strain during the loading cycles, we were also able to show that inelastic attenuation is nearly constant (Q ≈ 5) over the four‐decade range of frequencies tested at a strain amplitude of 10−3. Interestingly, the viscous effects only appear when loading a sample beyond its preconsolidation. Triaxial tests show that the relationship between differential stress and axial strain is positively dependent on axial strain‐rate, and that unconsolidated sand continues to deform viscously even at large strains (∼7%). All experiments were conducted at room temperature and humidity. A limited number of experiments with unconsolidated reservoir sand from the Gulf of Mexico show similar behavior.

Viscous deformation of unconsolidated reservoir sands—Part 2: Linear viscoelastic models

Laboratory creep experiments show that dry unconsolidated reservoir sands follow a power law function of time (at constant stress), and cyclic loading tests (at quasi‐static frequencies of 10−6 to 10−2 Hz) show that the bulk modulus increases by a factor of two with increasing frequency while attenuation remains constant. In this paper, we attempt to model these observations using linear viscoelasticity theory by considering several simple phenomenological models. We investigated two classes of models: spring‐dashpot models, which are represented by exponential functions with a single relaxation time, and power law models. Although almost all of the models considered were capable of fitting the creep data with time, they result in very different predictions of attenuation and bulk modulus dispersion. We used the model parameters derived from fitting the creep strain to predict the bulk modulus dispersion and attenuation as a function of frequency, to find a single phenomenological model (and model parameters) that could explain the material's creep response with time as well as its dispersion and attenuation characteristics. Spring‐dashpot models, such as the Burgers and standard linear solid models, produce reasonable fits to the creep strain and bulk modulus dispersion data, but do not reproduce the attenuation data. We find that a combined power law–Maxwell creep model adequately fits all of the data. Extrapolating the power law–Maxwell creep model out to 30 years (to simulate the lifetime of a reservoir) predicts that the static bulk modulus is only 25% of the dynamic modulus. Including the instantaneous component of deformation into the previous prediction results in 2% total vertical strain at the wellbore, in good agreement with field observations.

Optimized Drill-In Fluid for an Openhole Gravel-Pack Completion

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 82279, "Optimized Drill-In Fluid Leads to Successful Openhole Gravel-Pack Completion Installation in Unconsolidated Reservoirs - Case History," by S. Cobianco, SPE, Enitecnologie, and E. Pitoni, SPE, P.N. Ricci, and M. Galli, Eni E&P Div., prepared for the 2003 SPE European Formation Damage Conference, The Hague, 13-14 May.

Mechanisms of Sand Production Through Horizontal Well Slots in Primary Production

Abstract Cold production in unconsolidated heavy oil reservoirs, where sand production is encouraged (CHOPS), has proven to be successful for vertical wells. However, the application of CHOPS to horizontal wells has been less profitable due mainly to excessive sand cleanout costs. Therefore, reducing sand cleanout costs by controlling sand production into horizontal wells while enhancing the surrounding permeability of the formation is an important factor in optimizing cold production from unconsolidated heavy oil reservoirs. This paper presents the results of an experimental investigation of the flow of oil and sand in the vicinity of a horizontal well under cold production. Specifically, the experiments physically simulated the flow of oil and sand into a slot in a horizontal well liner. The parameters studied include slot width and sand properties (morphology and grain size distribution). Experimental results suggest that sand production through horizontal well slots can be controlled, depending more on sand grain sorting than on grain morphology or average diameter. The sand cut had a tendency to be higher at the beginning of the sand production period and to decline with time. In most tests, the decline in sand cuts continued until no more sand was produced. Significant changes in the permeability and porosity were determined in the vicinity of the slot. The changes in the parameters were less significant away from the slot. The largest fractions of the sand (bigger than 500 µm) have an important role in arch/bridge formation. Introduction Cold production is a primary non-thermal process used in unconsolidated heavy oil reservoirs in Alberta and Saskatchewan, Canada. In this process, sand and oil are produced together in order to enhance oil recovery(1–3). A comprehensive review of cold production has been presented by Tremblay et al.(1). Hall and Harrisberger(4) found that arch stability was flow rate sensitive at low confining stress but independent of flow rate at high confining stress levels. They observed that angular sand without compaction did not form an arch. When a moderate compaction was applied, it could lead to a slightly stable arch. A better interlocking of the surface grains was the explanation for this result. For round sand, arching was not observed for a loose or dense pack at low loads. Yim et al.(5) observed that in addition to the flow rate, the arch stability was strongly dependent on the granulometry of the sand and on the size of the perforation. Larger perforations required larger grains to form stable arches. McCormack(6) conducted experimental work with spherical particles to determine the arching/bridging mechanism that influenced the performance of wire-wrapped sand screens. Selby and Farouq Ali(7) showed that sand production increased as the overburden pressure and the fluid flow rate were increased. They also found that spherical small grain sand packs can produce more sand than angular large grain sand packs. Cleary et al.(8) observed that the structure of an arch depended on the stress distribution in a sand pack. The cohesive force was shown to have an important role in arch stability when different hydrocarbons liquids were used.

ROCK PHYSICS—APPLICATION TO GEOLOGICAL STORAGE OF CO2

Sequestration of anthropogenic CO2 into underground brine-saturated reservoirs is an immediate option for Australia to reduce CO2 emissions into the atmosphere. Many sites for CO2 storage have been defined within many Australian sedimentary basins. It is anticipated that seismic technology will form the foundation for monitoring CO2 storage within the subsurface, although it is recognised that several other technologies will also be used in support of seismic or in situations where seismic recording is not suitable. The success of seismic monitoring will be determined by the magnitude of the change in the elastic properties of the reservoir during the lifecycle of CO2 storage. In the short-term, there will be a strong contrast in density and compressibility between free CO2 and brine. The contrast between these fluids is greater at shallower depth and higher temperature where CO2 resembles a vapour. The significant change in the elastic moduli of the reservoir will enable time-lapse seismic methods to readily monitor structural or hydrodynamic trapping of CO2 below an impermeable seal. Because the acoustic contrast between brine saturated with CO2 and brine containing no dissolved CO2 is very slight, however, dissolved CO2 is unlikely to be detected by any seismic technology, including high-resolution borehole seismic. The detection of increases in porosity, associated with dissolution of susceptible minerals within the reservoir may provide a means for qualitative monitoring of CO2 dissolution. Conversion of aqueous CO2 into carbonate minerals should cause a detectable rise in the elastic moduli of the rock frame, especially the shear moduli. The magnitude of this rise increases with depth and demonstrates the potential contribution that can be made from repeated shear-wave and multi-component seismic measurements. Forward modelling suggests that the optimal reservoir depth for seismic monitoring of CO2 storage within an unconsolidated reservoir is between 1,000 and 2,500 m. Higher reservoir temperature is also preferred so that free CO2 will resemble a vapour.

Simulation of Sand Production in Unconsolidated Heavy Oil Reservoirs

Abstract Previous research on sand production prediction focused on when sand will be produced during depletion based on some mechanics analyses, but the amount of sand production was ignored. Recently, more and more researchers are focussing on the simulation of heavy oil sand production processes. For an unconsolidated heavy oil reservoir which employs sand production to enhance production, the amount of sand production is of great importance, because too much sand production may cause near wellbore instability, while too little sand production may not maximize well productivity. In view of this, based on both fluid flow modelling and reservoir mechanics concepts, a coupled heavy oil/sand particulate flow/reservoir elasto-plastic deformation model is used to simulate sand production, oil production, and reservoir deformation. With this model, we can determine an optimum flow rate which will not cause near wellbore instability while maximizing well productivity. Introduction Heavy oil sand production as an important production enhancement measure has been used in the primary development of heavy oil reservoirs in Canada for a long time. The production of sand may lead to the change of formation flow-related parameters such as permeability, porosity and mechanical parameters such as cohesion, and it also causes near wellbore stress redistribution. Thus, sand production is a very complicated process involving both fluid flow and geomechanical problems. In order to simulate the effect of sand production and productivity enhancement, simulation of the physical process needs to be done. Because of the long history of cold production, the simulation of cold production is becoming mature and a lot of excellent work has been done by experts in Canada and elsewhere around the world(1–5). Wang(1) developed a model to predict sand production in a heavy oil reservoir in Frog Lake at Lloydminster, Canada. It is believed that reservoir depletion induces stress concentrations around the wellbore, and large drawdown causes a foamy oil zone, in which large drawdown and seepage forces are created which causes sand production. A fully coupled geomechanical, foamy oil flow model was developed. Sand production is assumed to start when the effective radial stress is equal to the tensile strength. Later Wang(2) developed a coupled reservoir-geomechanical model to simulate the enhanced production phenomena in both heavy oil reservoirs (Northwestern Canada) and conventional oil reservoirs (North Sea). It is believed that the production enhancement is contributed:by the reservoir porosity and permeability improvement after a large amount of sand is produced, andby the higher mobility of the fluid due to the movement of the sand particles. Once the reservoir formation yields plastically, loose sand particles can be generated. Sand production has been postulated as a critical condition when the effective radial stress reaches the tensile strength or when the plastic strain reaches the critical plastic strain. Recently, Papamichos et al.(3) and Stavropoulou et al.(4) also provided their model to simulate sand production. Later Papamichos et al.(5) applied successfully this model to interpret sand production from a North Sea reservoir.

Use of Coupled Reservoir and Geomechanical Modelling for Integrated Reservoir Analysis and Management

Abstract Reservoir engineering (and simulation) have historically paid little attention to the geomechanical behaviour of porous media. However, a number of important (primarily unconventional) recovery processes can be properly engineered only by including this effect (e.g., thermal recovery in oil sands, compaction drive in soft and unconsolidated reservoirs, chalk reservoirs, stress sensitive and microfractured media, waterflooding at fracture pressure, waste injection, coal seam stimulation, etc.). In addition, analysis of drilling and completion problems, such as wellbore stability, sand production, fracturing or casing failure, requires knowledge of geomechanical behaviour of the reservoir. This paper gives an overview of the geomechanics of reservoir behaviour, describes recent advances in coupled reservoir and geomechanical modelling, and presents case studies of field applications of this new tool. The examples show the potential of the coupled modelling to become a comprehensive tool for integrated reservoir management, including reservoir, production and drilling aspects of field development. In each case, the use of the new, more comprehensive tools provided better understanding of recovery mechanisms, and changed significantly the economic evaluation of the project. Introduction The geomechanical behaviour of porous media has become increasingly important to hydrocarbon operations. Numerical modelling of such processes is complex, and has been historically carried out in three separate areas: geomechanical modelling (with the primary goal of computing stress/strain behaviour, and its consequences in production engineering), reservoir simulation (essentially modelling multiphase flow and heat transfer in porous media), and fracture mechanics (dealing in detail with crack propagation and geometry). In reservoir management, the geomechanical aspects of the engineering often bridge the various engineering specialities. In fact, the term "geomechanics" is often being applied very broadly to describe a wide range of reservoir phenomena. Examples of the engineering problems involving geomechanics include:Wellbore stability during drilling (in shales and in the reservoir)Wellbore stability of open hole completions during production (in particular for horizontal wells)Reservoir compaction and subsidenceManagement of stress-sensitive reservoirs (in which permeability and porosity change with stress)Naturally fractured reservoirs (fracture systems are stress sensitive)Integrity of completions during production (casing failures)Sand production (prediction of stability and minimization or prevention)Analysis and engineering of waterflooding above fracture pressure (so called "thermal fracturing")Recovery processes in unconsolidated sands (heavy oils and oil sands), including sand failure, dilation, microchanelling and wormholing, and cold productionConventional and unconventional hydraulic fracturing (fracpack, high permeability soft formations...)Completion and reservoir engineering of coalbed methane wells (fracturing, wellbore cavitation, productivity)Waste disposal at fracturing pressure (oilfield, radioactive, chemical,..)Drilling cuttings reinjectionProduced water reinjection (PWRI), in particular in "soft" formations. The common feature of all of these problems is the strong interaction of the behaviour of the solid (porous matrix and fractures) with the reservoir fluid flow and potentially induced fractures. Consequently, the analysis using conven

Modelling Cold Production for Heavy Oil Reservoirs

Abstract The term "Cold Production" refers to the use of operating techniques and specialized pumping equipment to aggressively produce heavy oil reservoirs. This encourages the associated production of large quantities of the unconsolidated reservoir sand, creating a modified wellbore geometry that could include "wormholes", dilated zones, or possibly cavities. As well, produced oil in the form of an oil continuous foam resembling chocolate mousse, suggests a foamy solution gas drive occurs in situ. This leads to anomalously high oil productivity and recovery because free gas stays entrained in the foam, thereby sustaining reservoir pressure. In a recent paper(1), the mechanisms that lead to this increased productivity were outlined and the suitable reservoir types conducive to cold production techniques were identified. In this paper, these mechanistic concepts are extended to practical, intuitive modelling techniques that can be applied to existing "black oil" reservoir simulators by appropriate alterations to the input data. Importantly, these techniques have beenound to match actual cold production behaviour in applicable Western Canadian conventional heavy oil reservoirs. With a history matched model, these techniques can be used to extend the cold production scenario into the future, providing better estimates of ultimate recovery. As well, sensitivities to the process can be investigated, including exploring sensitivities to various reservoir and operating parameters (e.g., reservoir pressure, production rate strategies) and examining the impact of a preceding cold production primary depletion on subsequent secondary and tertiary recovery processes. Introduction In approximately the last ten years, many authors have written about the phenomena involved in producing heavy oil by solution gas drive. Their work has been inspired by field observations of cold production in some of the heavy oil reservoirs in Canada and enezuela, where unexpectedly high oil rates and recoveries, as well as low gas-oil ratios, have been attained. This work has included laboratory investigations of fluid and rock properties (including geomechanical studies of the so-called wormholingeffects), conceptual postulation of mechanisms in the context of actual field behaviour, as well as some attempt to mathematically capture and numerically model these mechanisms. Perhaps one of the first to set forth the mechanisms and possible mathematics was Smith(2) at Husky, who also appears to be one of the first investigators to note that the anomalous production enhancement must arise from a combination of geomechanical and fluid effects (i.e., results cannot be "excused as high permeability channels resulting from sand production"). These two categories of mechanisms"geomechanical effects and fluid effects?are the subject of the mechanisms proposed in the literature for explaining the cold productionperformance of heavy oil reservoirs. Geomechanical Effects Productivity of heavy oil wells experiencing cold production is typically much higher than would be expected"actual productivity exceeds radial Darcy flow predictions (using typical oil viscosities and air permeabilities) by factors of four to 10.

Sand Deposition Inside a Horizontal Well-A Simulation Approach

Abstract Horizontal wells have been shown to be successful in improving oil recovery for marginal heavy oil reservoirs in Saskatchewan and Alberta. One commonly encountered problem in recovery operations for these poorly consolidated reservoirs is the production of sand and fines into the horizontal wellbore, where they settle and accumulate. This paper reports the numerical modeling of gravitational deposition of sand in a horizontal well in such heavy oil reservoirs. The numerical model described in this work examines the transport process mechanistically, based on the conservation equations for the fluid phase (heavy oil) and the solid phase (sand particles). The interaction between these phases is described by empirical correlations. The equations are solved numerically to determine the concentration of sand particles and oil, and their respective pressure and velocity distributions inside the horizontal well. According to the simulation results, oil viscosity and particle size play important roles in the transport process, including controlling the gravitational settling tendency of solid particles inside the horizontal wellbore. The results provide insight into the roles different mechanisms affect the transport of sand particles; as such, they provide guidelines for production operations involving horizontal wells in poorly consolidated and unconsolidated reservoirs. Introduction The use of horizontal wells, in Saskatchewan and Alberta heavy oil reservoirs underlain with bottom-water, has been found to improve primary recovery performance prior to water coning-recovering up to 15%, in some cases, of the initial oil in place, compared with only 5% for a vertical well(1). Horizontal wells have also been successfully used for increasing steamflood recovery(2,3). Due to the unconsolidated or poorly consolidated nature of these reservoirs, solid (sand and fines) production is quite prevalent. The produced solids lead to several production problems, including sand filling up the wellbore, preventing the operation of downhole pumps and surface equipment, etc.(4) In horizontal well cases, sand production potentially poses a serious problem, as the sand could settle and accumulate inside the horizontal wellbore. This settlement and accumulation of sand particles could give rise to reduced cross-sectional areas of the wellbore open to flow. The study reported in this paper examines, using numerical simulation, the gravitational deposition of sand particles inside a horizontal wellbore. A brief survey of the relevant literature is given in the following. Solid-liquid multiphase flows are usually very complex, due to the large number of variables involved in the transport processes, and typically poorly understood interaction between the variables. There have been many experimental investigations of these (and other) flow processes, particularly focused on the deposition of the solid particles. Many of the earliest investigations of solid liquid flows focused on the settling tendency of solid particles. Richardson and Zaki(5) experimentally determined that the falling velocity of a suspension relative to a horizontal plane was equal to the upward velocity of the fluid required to maintain a suspension at the same concentration. For different flow regimes (i.e., Reynolds numbers), separate correlations were developed (from experimental data) for the exponent which corresponds to the slope of log-log plot straight lines between suspension falling velocities and suspension porosities.

Measuring Compaction and Compressibilities in Unconsolidated Reservoir Materials by Time-Scaling Creep

Summary A testing procedure and analysis method is proposed that gives compaction and compressibility data that are independent of test duration for unconsolidated sands. Compaction data on unconsolidated sand material [including several Gulf of Mexico (GOM) reservoirs] derived from this method are presented. Tests on twin plugs give essentially the same stress-strain data for test durations from one day to three months. This occurs because of a fundamental time-scaling property of these unconsolidated materials. The creep behavior is modeled with a fractional power law dependence with time, which represents the Voigt material model having an extremely broad distribution of relaxation times. This analysis indicates that the characteristic relaxation times of these materials are measured in decades or longer. Creep equilibrated tests are, therefore, impractical and not relevant to a reservoir that will be depleted in one or two decades. Analysis of the power law creep parameters indicates the creep behavior is consistent at higher stresses among the materials tested. The creep parameters scale with stress and provide a means of decoupling the time-dependent behavior from the stress-strain behavior.

Appraisal of a Viscous Oil Accumulation in Unconsolidated Sand Reservoirs Using Horizontal Wells: Captain Field, Block 13/22a, Inner Moray Firth, North Sea, UKCS: ABSTRACT

Appraisal of a Viscous Oil Accumulation in Unconsolidated Sand Reservoirs Using Horizontal Wells: Captain Field, Block 13/22a, Inner Moray Firth, North Sea, UKCS: ABSTRACT

Thermal stresses near a circular opening in an unconsolidated reservoir : Wang, Y; Scott, J D; Dusseault, M B Proc 33rd US Symposium on Rock Mechanics, Santa Fe, 3–5 June 1992P387–396. Publ Rotterdam: A A Balkema, 1992

Thermal stresses near a circular opening in an unconsolidated reservoir : Wang, Y; Scott, J D; Dusseault, M B Proc 33rd US Symposium on Rock Mechanics, Santa Fe, 3–5 June 1992P387–396. Publ Rotterdam: A A Balkema, 1992

Permeability and Hydraulic Zone Predictions in Unconsolidated Reservoirs from Log and Core Data

Permeability and Hydraulic Zone Predictions in Unconsolidated Reservoirs from Log and Core Data

Comparison of Acoustic Impedance and Time-amplitude Analysis Techniques for Reservoir Description of a Gulf of Mexico Shelf-edge Clastic Field

Post-stack, time-amplitude techniques are routinely used in the estimation of reserves and the positioning of wells in low impedance, unconsolidated reservoir sands in the offshore Gulf of Mexico (Texas and Louisiana). Time amplitude analysis of 3D seismic data, when properly calibrated, can yield reliable estimates of net hydrocarbon pay, reservoir distribution, and volumetrics. Acoustic impedance (Al) analysis can also be used for such prospect appraisal and development work. However, the combined use of both techniques for reservoir description is not common. Some advantages in acoustic impedance (over amplitude analysis) are: (1) properly constrained Al traces better image the reservoir rock configuration (that is, they provide a more [open quotes]geologic[close quotes] view) thereby facilitating interpretation of reservoir distribution and interconnectivity, and (2) Al volumetrics methodology can provide more accurate estimates of average pay for reservoirs that are not seismically isolated from one another. A possible disadvantage is the difficulty in incorporating a proper baseline (low frequency) constraint for the required Al trace inversion. This paper reports the advantages and disadvantages of both techniques in characterizing net pay, volumetrics, and reservoir continuity in a producing Gulf of Mexico oil field in a shelf-edge delta depositional system.

Crosswell imaging in a shallow unconsolidated reservoir

It has long been recognized by the oil industry that its future will rely more and more on the recovery of products from existing fields. The need for more efficient recovery drives the desire to know more about the reservoir structure and composition. Crosswell tomography is among the most promising of our geophysical utensils for reservoir characterization, as evidenced by its ever‐increasing application in EOR monitoring. Although it is a relatively new method, the literature shows that crosswell tomography works quite well in highly consolidated lithology where good data quality, in terms of signal‐to‐noise ratio and raypath coverage, is achievable. The case to be addressed here, however, is the one that occurs under more hostile conditions. Our intention is to show the ability of crosswell traveltime tomography in circumstances where data quality is lower than usual.

Solid Particle Impact Erosion Testing Of Texaco Filter Elements And Selected Well Completion Materials

Abstract In-situ heavy oil, oil sand pilots, and conventional oil production located in unconsolidated sand reservoirs, have experienced a variety of problems related to plugging dissolution of silica sand conventionally used as a filter-pack, and erosion. The erosion is followed by a massive inflow of sand into the production wells resulting in reduction of flow capacity. To alleviate some of these problems, a new metallic filter of high porosity was designed and field tested. It employed steel wool elastically compressed arid sandwiched between inner and outer high-resistance mandrels. Field testing of the new filters has revealed some erosion-associated problems and a laboratory program was initialed to find the optimal design criteria for reducing the erosion damage. For the first time, the capacity of compressed metallic wool to withstand erosion was experimentally assessed. Standard sand-Jet blasting equipment was calibrated and used to determine penetration time for common well-material coupons and for compressed metallic wool filters. Filters having the compression factors ranging from 5 (density = 0.15) to 30 (density = 0.92) and metallic wool depth from 6 mm ro 19 mm were exposed to the erosion tests and results are presented graphically and analytically. It appears that increasing the wool density or filter thickness lead to an optimum value resulting in maximum filter erosion resistance. Photomicrographs of the eroded zones are presented in order to explain some of the mechanisms involved. Introduction In-situ recovery pilots(1) and conventional oil production located in unconsolidated sand reservoirs have experienced a variety of problems related to filter-pack erosion and massive inflow of sand into production wells. As a result, considerable research sponsored by Texaco Canada Resources, was conducted at the Alberta Research Council, into new types of well completion, that would alleviate solids intrusion. To address the problems related to the dissolution or gravel packs in a high-temperature, high-pH environment and to improve flow conditions and skin-effect identified by excessive pressure drop in the wellbore region, a solids control device was developed by the Alberta Research Council and Texaco(2) The Meshrite* filter employed steel wool sandwiched between inner and outer mandrels, designed to be part of the outer well casing directly in contact with the formation (Fig. 1). A field testing program in Athabasca, revealed difficulties associated with erosion of the filter by formation solids. The presence of high permeability zones in the vicinity or the production well resulted in preferentially high fluid-velocity streams. Entrained formation solids impacting the well, tend to erode holes through the downhole filter elements as illustrated in Figures 2, 3 and 4. As a result of these field tests, a research program was initiated in 1987 to study methods of assessing and improving the erosion resistance of the Meshrite filter and well completion materials such as 155 and N80 tubing and casing steels. The field filters constructed to date have used wool with a bulk density in the range of 0.6 g/cm3 (compression factor of 20) with a thickness of 9.5 mm.