Accurate Measurements of Seabed Subsidence Above Norwegian Gas Fields

Withdrawal of oil and gas from reservoirs causes a decrease in pore pressure and an increase in the effective stress which leads to reservoir compaction. Reservoir compaction can be result in surface subsidence through the elastic response of the subsurface layers. To determine the subsidence above a hydrocarbon field, the reservoir compaction must first be calculated, and then, the effect of the reservoir compaction on the surface is modeled. The use of the uniaxial compaction theory is a more customary and accepted method for determining the amount of reservoir compaction induced by pressure depletion. Surface deformation above compacting reservoirs can be efficiently modeled using influence functions. In this paper, Knothe and Geertsma influence functions were used in a simple approach for subsidence modeling of the South Pars gas field. In this approach, we used circular network, called influence network, for determining the whole reservoir compaction effect on the field surface. In addition, the subsidence of the South Pars gas field is modeled using the AEsubs software, and the results are compared to the predicted subsidence by the influence functions.

Discovered on the shallowest formation in Myanmar offshore field at 500 meters subsea, this reservoir is perhaps one of the most challenging reservoirs to develop in many aspects such as; risk of fracking to seabed when performing sand control completion, cap rock integrity and risk of breaching due to completion and production activities, reservoir compaction, and depletion-induced subsidence. Generally, the producing reservoirs currently developed in this field sits between 700 to 2500 meter subsea, mTVDss. Cased Hole Gravel Pack (CHGP) as sand control completion method is selected to develop the reservoir from 700 to 1650 mTVDss. None of the shallow reservoirs (shallower than 700 mTVDss approximately) has been developed in the field before, due to some technical challenges previously mentioned. Owing to these reasons, reservoir engineer and well completion team initiated feasibility study focusing on advanced Geomechanical modeling and alternative way of sand control completion combined with full project risk assessment, ultimately, to unlock huge gas reserves trapped in this field. The reservoir is finally developed with infill well and new completion technique ever been used in the company. To develop this shallow reservoir, infill well drilling with sand control completion is required. The technical analysis on the following problems was comprehensively performed to ensure that the reservoir was feasible, doable and viable to develop. Reservoir compaction and subsidence occurring with stress and pressure changes associated with depletions would not create potential hazard to production facilities. Cap-rock is stable with no breaching over entire life of reservoir depletion. No potential fault is reactivated upon depletion. Sand control completion is able to be performed safely with well-confined fracpack (risk of frac growth to seabed). Upon depletion, integrity of casing and cement is acceptable when reservoir is compacted. Full risk assessment aspects of completion operation are scrutinized. These problems were mainly analyzed using coupled 3D Geomechanical model focusing on this shallow reservoir in the area of this particular wellhead platform. Briefly speaking, the 3D Geomechanical model was coupled with reservoir pressure depletion to find stress and displacement of reservoir rock and casing due to production. The methodology is called one-way coupled modeling. To be more precise, the pre-production stress of the reservoir at initial pressure was determined and used to calculate subsequent stress change from depletion (production). Pressure depletion will increase effective stress and hence create deformation of reservoir rock which may induce underground subsidence and casing integrity. On this study, four stress-steps of pressure depletion were computed i.e. initial pressure, 25% depletion, 50% depletion and 75% depletion. On each step, stress equilibrium was simulated using finite element software. This project makes the pending development of shallow reservoir in this field doable and viable. All risks associated with well completion and production-induced depletion were deliberately reviewed and mitigated. Based on this study, the most critical risk is gas leak through seabed due to sand control completion activity (CHGP). Apart from this, the other risks such as seabed subsidence, cap-rock breaching, fault reactivation, and casing integrity upon compaction were consciously addressed, reviewed and prevented. The major risk on sand control completion was finally mitigated. The conventional extension pack was avoided and replaced with the completion technique, a so-called circulating pack. Circulating Pack is one of CHGP technique where the pumping rate and pumping pressure maintained below fracture extension rate and fracture extension pressure. This pumping rate and pumping pressure will not introduce the fracture in the formation but still able to carry proppants and place them in the annular between screen and casing to provide sand control means. Although the sand control performance of circulating pack is not up to High Rate Water Pack (HRWP) or Extension Pack, together with control of minimum drawdown and production rate will enhance the sand control performance and prolong production life. Ultimately, unlock the potential in this shallow reservoir. The well has finally been successfully completed under tailor-made design and real-time data acquisition. The reservoir has been producing successfully with the rate of about 5 MMSCFD with good flowing wellhead pressure at 590 psi similar to the design. Ultimately, this alternative approach enables the development of this shallow reservoir where the new reserves of 20 BSCF has been added to the project. This project can be a good lesson for future development of other shallow reservoirs worldwide.

A study was conducted on Field M to assess CO2 storage potential and to evaluate the risks and uncertainties based on an integrated dynamic-geomechanics modeling approach. Field M is located at north of Central Luconia Province in Sarawak Basin, Malaysia. Most of the depleted carbonate formation in Sarawak Basin undergone pore collapse at various rates during its production life. In order to consider the impact of pore collapse towards reservoir properties, a seamless coupling simulation approach between dynamic model and geomechanics model is important to generate robust storage capacity and storage containment integrity assessment. The high abandonment pressure, uncertainties caused by reservoir compaction during the production life and subsequent injection period, and the risk of CO2 leakage from the reservoir due to fault re-activation and cap-rock integrity breach by the injection operations are also evaluated. The assessment was undertaken by building the compositional dynamic model that was then history matched in standalone mode to the historical production data with a reasonable quality index. The dynamic model grid was embedded with overburden, underburden and sideburden in the geomechanics model grid, and the reservoir properties and embedment grid properties were then populated in the geomechanics model. This process was followed by another history match in 2-way fully coupled dynamic-geomechanics modeling approach whereby the reservoir production and pressure depletion, and subsidence were matched. Injection simulations were subsequently conducted to assess the impact of reservoir compaction, trapping mechanisms, fault stability and cap-rock integrity towards achieving the maximum injectivity and storage capacity. It was observed that 4.41% of porosity and 12.11% of permeability reduction associated with reservoir compaction occurred during production whilst there was limited reversal in both parameters’ reduction during injection as the rock deformation was largely irreversible plastic deformation. The simulated subsidence was matched with the actual 20-year GPS subsidence measurement data collected at platform location. This history matched 2-way fully coupled model was subsequently used as the base case for simulating the CO2 injection options. The simulations showed that Field M has the potential to store up to 2.3 Tscf until the pressure reaches the cap-rock pressure limit. The simulations also showed that all the faults and cap-rock maintained their integrity and the seabed uplifted by 0.05 ft during the end of injection period. This paper provides a detailed description on CO2 storage site assessment using a 2-way fully coupled dynamic-geomechanics modeling approach in a highly porous carbonate reservoir which addresses trapping mechanisms, fault stability and cap-rock integrity, and their impact on injectivity and storage capacity. The information may be adopted for evaluation of other CO2 storage projects in b oth carbonate and clastic reservoirs worldwide ensuring their safe long-term storage.

A thorough 3D finite-element (FE) geomechanical study was over undertaken for an oil and gas field offshore Sarawak, Malaysia, to assist the development management. The field comprises eight major reservoirs with three of them planned for water injection to improve recovery. The historical well drilling data, wireline logs, production data, field tests and newly obtained laboratory test data provided inputs for deriving a wellbore-based 1D geomechanical model for the field. The 1D model was calibrated to well drilling observations before being up-scaled and populated in a 3D geomechanical model for the entire field. The model was implemented in an FE simulator to dynamically analyze reservoir compactions, platform site subsidence, fault reactivation potential and cap rock breaches that might be induced by reservoir depletion and injection in the full life cycle planning of the field management. The results showed a maximum subsidence of 0.72 m above the shallowest depleting reservoir and a subsidence of approximately 0.62 m at the seabed in year 2032. Injection slightly reverses the subsidence induced by depletion and the subsidence at the centre of the seabed is approximately 0.58 m in year 2050. The corresponding subsidence at the platform sites reaches 0.58 m in year 2032 and reduces to 0.54 m in year 2050. Depletion tends to reduce fault reactivation potential within the depleting and close underlying intervals, but enhances fault slip likelihood near the upper bounding zones. Faults segments bounding the deepest producing reservoir, which contains the most depletion, is predicted to have the highest potential for fault shearing in the late stages of production. Injection reverses the trend of fault reactivation potential. There are no caprock integrity issues with the three main injection reservoirs for the entire field life. Introduction The study field is in offshore Sarawak, Malaysia and truncated by two sets of major faults with one set (Alpha) in the south and the other (Beta and Gamma) in the north of the field. There are dozens of hydrocarbon-bearing zones separately deposited in the upper to lower coastal plain environments of interbedded sandstones, shales and siltstones. The shallower zones comprise gas reservoirs; intermediate reservoirs exhibit small oil rims; and deep reservoirs show gas condensate. Eight reservoirs, labelled as R1, R2, … and R8, have been either in production, or in water injection, or within future production consideration. Fig. 1 shows the plan and cross-section views of the field structure. After the field discovery in 1967, production commenced in 1972 from three major reservoirs: R4, R5 and R6, with R6 started water injection since 1994 follow by R4 and R5- in 2017. In addition, the other 5 reservoirs, including a deeper overpressured pure gas reservoir, R8, will begin production in 2017. Thereafter, depletion and recharge of pressure is expected from multiple reservoirs undergoing either production or injection. Pressure depletion from production or pressure recharge because of injection induces stress changes in the depleting/injecting reservoirs and their bounding formations. Consequently, the stress changes in multiple reservoirs and bounding zones can induce various geomechanical problems, e.g., wellbore drilling instability, sand production, reservoir compaction, overburden subsidence, fault reactivation and caprock fracturing. Those geomechanical issues can impact well planning, platform facilitating and production management for future field development.

On November 26, 2009 a 2.8-magnitude earthquake occurred in southwestern Friesland in the Netherlands at an approximate depth of 2 km. This relatively shallow depth indicated that the event was induced, instead of being natural. Closest mining activities were supposed to be the Weststellingwerf field with well WSF-01 and the exploration well DHV-01. The event was named De Hoeve. However, production from DHV-01 started after the event was occurred. Thus, a study was required to determine the origin of the tremor, evaluate if it could be followed by other tremors in the future, and estimate its magnitude. The objective of this paper is to present the study that was conducted in order to identify whether the gas production and water injection in well WSF-01 could have caused the so-called Weststellingwerf fault to slip leading to the earthquake as observed in November 2009. The following work plan was devised: 1) Perform seismic interpretation; 2) Construct fit-for-purpose geological model of Weststellingwerf area; 3) Construct reservoir simulation model; 4) History match production data of two wells and record pressure and temperature distribution as a function of time; and 5) Build 2-D geo-mechanical model, feed geological data and structure into model, feed pressure and temperature from dynamic model into geo-mechanical model, assign reasonable geo-mechanical properties, perform stress calculations at critical time steps, and determine potential slip displacement along Weststellingwerf fault. Five triggering mechanisms were tested: 1) Salt dissolution; 2) Pressure depletion during gas production; 3) Re-pressurization due to water injection; 4) Thermal stresses due to cold water injection; and 5) Fault weakening due to water injection (chemical alteration) Geo-mechanical simulations showed the causes of the earthquake should be looked for, not in stress variations along Weststellingwerf fault, but instead in a fault weakening upon first contact with water. Two mechanisms can be at the origin of this reduction: fault lubrication or decrease in capillary pressure in the fault gouge material when it was first contacted by water. The simulations also showed that no earthquake should occur in the section of the fault where displacements occurred during de Hoeve tremor. Sections that did not show any displacement could be at the origin of new earthquakes when first contacted by water, but probably of lower magnitude.

The study field has been an oil-producing area in southern Iran for nearly 50 years. Complex geological structure and varying levels of depletion scenarios require geomechanical analysis of the reservoir to enhance its production and mitigate geomechanical risks. This paper describes creating a time-lapse (4D) integrated geomechanical model by generating 3D maps of mechanical properties and a 3D stress state that can be altered over time as pore pressure changes, then explores pressure depletion and related stress changes effects on faults and fractures reactivation. The first phase of the study was an integrated stress analysis using Image logs and sonic anisotropy interpretation. 1D–3D Mechanical Earth Model was built by gridding the reservoir and populate the model with mechanical properties. The third phase provided a distribution of stresses and associated strains under initial conditions using finite element calculations. Ultimately, stress and strain changes associated with depletion simulated by the reservoir flow model were determined during the fourth phase of study. In the resulting model, different critical coordinates points from the initial year (1992) to 2045 were selected five time-steps. Results show no critical faults reactivation but by increasing production time the instability of fractures gradually rises by stress regime changes.

Highlights: • A novel workflow integrates multiphase flow and geomechanical models to determine site-specific CO₂ injection pressure limits. • Injection rates of up to 1.7 Mt CO₂/year per well are sustainable under reservoir constraints, with higher rates achievable due to a 10 MPa increase in pressure governed by the cap rock’s tensile strength. • Vertical wells exhibit an injection limit of ∼18 MPa/km, while horizontal configurations extend this to ∼20 MPa/km, highlighting the influence of well geometry on injection strategy design. • At the investigated storage site, overpressure in the reservoir and cap rock remains compressive over a 100-year period, confirming robust containment and long-term storage integrity. Abstract Geological carbon capture and storage (CCS) in saline formations is seen as a plausible short-term solution to reduce atmospheric carbon dioxide (CO₂) concentrations and mitigate climate change. Besides storage capacity, largely determined by pore space within a geological trap, the maximum allowable pressure in the storage formation represents a major limitation for geological CO₂ storage. This study, therefore, addresses the hydromechanical aspects of geological CO₂ storage by developing an integrated workflow to determine site-specific injection pressure limits and applying it to a potential storage site in the German North Sea sector. The workflow ensures consistency between reservoir flow and geomechanical models by automatically extracting near-wellbore geomechanical domains from the large-scale model. For a vertical well, the site-specific injection pressure limit is estimated at 17.9 MPa/km, governed by tensile failure in the storage formation. Within the cap rock, the limit increases to 28.6 MPa/km, providing a large margin of safety and enabling higher injection rates. A horizontal well configuration yields a slightly higher limit of 19.7 MPa/km, due to the larger well-reservoir contact area and improved pressure dissipation. The derived pressure limits are subsequently implemented in a large-scale dynamic simulation to verify workflow performance and assess formation integrity. Results indicate that injection rates of approximately 1.7 Mt CO₂ per year per vertical well can be sustained over 30 years, with reservoir overpressure and the corresponding stress states strongly dependent on the hydraulic setting of the reservoir. Importantly, injection-induced stresses and thus the probability of fracture formation decreases rapidly after CO₂ injection ends.

Chapter 9 - Fluid Flow Equations

Summary Subsurface flow modeling is an indispensable task for reservoir management, but the associated computational cost is burdensome because of model complexity and the fact that many simulation runs are required for its applications such as production optimization, uncertainty quantification, and history matching. To relieve the computational burden in reservoir flow modeling, a reduced-order modeling procedure based on hyper-reduction is presented. The procedure consists of three components: state reduction, constraint reduction, and nonlinearity treatment. State reduction based on proper orthogonal decomposition (POD) is considered, and the impact of state reduction, with different strategies for collecting snapshots, on accuracy and predictability is investigated. Petrov-Galerkin projection is used for constraint reduction, and a hyper-reduction that couples the Petrov-Galerkin projection and a “gappy” reconstruction is applied for the nonlinearity treatment. The hyper-reduction method is a Gauss-Newton framework with approximated tensors (GNAT), and the main contribution of this study is the presentation of a procedure for applying the method to subsurface flow simulation. A fully implicit oil/water two-phase subsurface flow model in 3D space is considered, and the application of the proposed hyper-reduced-order modeling procedure achieves a runtime speedup of more than 300 relative to the full-order method, which cannot be achieved when only constraint reduction is adopted.

The successful development of unconventional reservoir relies on the massive hydraulic fractures which provide high conductive paths and large contact area between matrix and wellbore. Since well production always shows a steep decline after the early high flow rate, refracturing can be an economically promising option to compensate for the loss of production and improve the well delivery. Although extensive field cases have been published on refracturing practice, there is a lack of guidelines on how to select and optimize refracturing design. In this paper, a series of synthetic cases are used to evaluate the well performance under different refracturing designs. The key characteristics for refracturing simulation is accurate quantification of the depletion-induced stress and pressure field change. Thus, finite element method is used to solve the coupled reservoir flow and geomechanics model while a cohesive zone model is adopted to simulate the fracture propagation. A viscoelastic model is used to simulate the time-dependent fracture conductivity change due to proppant embedment. The synthetic cases are grouped into two categories: refracturing in existing perforations and in newly created perforations. A systematic sensitivity study is performed on the effects of fracturing spacing, matrix permeability and refracturing time. Numerical results show different fracture configurations for refracturing in depleted and virgin reservoirs and thus demonstrate the importance of accounting for stress and pressure changes during initial production. Refracturing the existing perforation is likely to create a wider but shorter fracture compared to the virgin case because the fracturing fluid in these fractures encounter less resistance for enlarging fracture width rather than fracture length because of reduced pressure and total stress. Refracturing new perforations appears to give better short-term performance than refracturing existing perforations but worse long-term performance. Simulation results indicate that for relatively low permeability reservoir it is favorable to add more fracture area; however, the advantage is diminished while for relatively high permeability reservoir where the SRV might already be depleted. When proppant degradation is severe, and fracture conductivity is the limiting factor for production, refracturing existing perforations becomes more attractive. Moreover, simulation results seem to indicate an optimum time window exists for refracturing in this scenario.

Recent advancements in technology have made possible studies of gas field development programs heretofore impossible. With the use programs heretofore impossible. With the use of a mathematical model, a method for solving the simulator equations, and adequate computing equipment, various development plans can be tested and evaluated. In evaluating a development scheme, we are concerned not only with the number of wells drilled, but also when each is drilled and the cost of each well.In order to obtain a plan for developing a gas field, there should be some criterion on which to base a decision on the location of additional wells. In this paper, we consider schemes resulting from the use of three distinct criteria. From the alternate schemes, a computer program determines the one which ultimately achieves the lowest cumulative present value cost.The subject field of this study is a portion of the Crossfield reservoir located portion of the Crossfield reservoir located near Calgary, Alta., Canada. The flow was considered single-phase, unsteady-state, isothermal, in a closed heterogeneous reservoir with a uniform porosity. An alternating direction iterative technique was used to solve the partial differential equations in the mathematical model.IntroductionThe goal in the natural gas industry is to locate adequate amounts of deliverable reserves and to produce them efficiently. Once a gas reserve has been located and dedicated to market, there are many things that must be considered in order to produce it efficiently: The production rate on the average and maximum day is usually specified. Gas sales contracts often require that the average delivered quantity be one Mcf/D/8 MMcf of reserve. This rate depletes about 90 percent of the reserve in 20 years. The operator drills sufficient wells to ensure that he can maintain the maximum daily requirement. Well productivity is checked at intervals, and the deliverability of the field is computed to ensure that it can continue to meet the market requirement. Well reconditioning or new wells may be required at certain stages in the life. If the reservoir is producing by pressure depletion and the gas producing by pressure depletion and the gas sales contract calls for a minimum pressure for delivering gas, field compressors may be installed as the field approaches abandonment pressure. pressure. With all these considerations'. it becomes immediately evident that a plan is needed for developing the field and placing the gas on the market. Estimates of gas reserves are needed as a basis for marketing the gas. Sufficient wells must be planned to produce the gas at the rates projected for delivery of the gas.At any stage of reservoir depletion, a correct estimation of the change in delivery capacity with time caused by depletion is essential for determining the number of wells required to meet a given contract to deliver gas. Fundamentally, the problem is the familiar one of obtaining data during the drilling, testing and early production life of a well and applying these data within a simulation model to predict long-term behavior. In planning the operation of a multiwell gas reservoir, it is desirable to predict its performance for each alternate development and producing schedule under consideration.p. 205

During recent years the authors and collaborators have been involved in an activity related to the construction and analysis of large time step operator splitting algorithms for the numerical simulation of multi-phase flow in heterogeneous porous media. The purpose of these lecture lecture notes is to review some of this activity. We illustrate the main ideas behind these novel operator splitting algorithms for a basic two-phase flow model. Special focus is posed on the numerical solution algorithms for the saturation equation, which is a convection dominated, degenerate convection-diffusion equation. Both theory and applications are discussed. The general background for the reservoir flow model is reviewed, and the main features of the numerical algorithms are presented. The basic mathematical results supporting the numerical algorithms are also given. In addition, we present some results from the BV (entropy) solution theory for quasilinear degenerate parabolic equations, which provides the correct mathematical framework in which to analyse our numerical algorithms. Two- and three-dimensional numerical test cases are presented and discussed. The main conclusion drawn from the numerical experiments is that the operator splitting algorithms indeed exhibit the property of resolving accurately internal layers with steep gradients, give very little numerical diffusion, and, at the same time, permit the use of large time steps. In addition, these algorithms seem to capture all potential combinations of convection and diffusion forces, ranging from convection dominated problems (including the pure hyperbolic case) to more diffusion dominated problems.

We present results of the 4D seismic monitoring of the Ekofisk field waterflood. The thick, high porosity chalk reservoir compacts strongly in response to water injection1,4,6. This compaction has a clear effect on the 4D seismic data, which has a baseline 3D survey acquired at the beginning of the waterflood in 1989, and a monitoring survey acquired in 1999. Ekofisk 4D seismic data has been a valuable qualitative tool for describing the spatial distribution of reservoir compaction and subsidence. The 4D data shows that some faults are significant barriers to water flow, and some reservoir compartments have been substantially compacted, from which we infer an increase in water saturation. These observations guide improvements to the reservoir simulation history match. The 4D seismic also helps explain recent drilling results and helps plan optimal well paths for future development drilling. Recent work to incorporate the 4D seismic into a compaction model gives quantitative reservoir compaction results that agree well with geomechanical and log-based compaction models. The seismic data can be used to monitor reservoir compaction over long time periods and serves as calibration data for detailed compaction modeling. Introduction The Ekofisk Field in the Norwegian Sector of the North Sea was discovered in 1969 and began production in 1971. In 1984, Phillips recognized that the seafloor over Ekofisk field was subsiding and determined that the cause was reservoir compaction. Since then, the seafloor subsidence has been monitored by repeated bathymetry surveys, and the reservoir compaction is monitored by measuring the movement of radioactive bullets implanted in wellbores in and above the reservoir1. The cumulative maximum subsidence today is more than 8m above the crest of the field, corresponding to a maximum reservoir compaction of 10m. The reservoir compacts by two mechanisms-pressure reduction associated with the initial production phase from 1971-1989, and waterweakening associated with the waterflood from 1989-present. A 3D seismic survey covering Ekofisk field coincided with the start of the field-wide water injection program. Phillips acquired a repeat 3D seismic survey in 1999 to monitor the waterflood-induced compaction by 4D seismic analysis. The Ekofisk field seismic data is not mappable at the crest of the field, due to overburden velocity anomalies associated with gas and overpressure. This appears as a blank area in the middle of all the seismic maps presented in this paper. Ekofisk 4D Seismic Observations In 1997, Phillips completed a time-lapse seismic feasibility Study2 that indicated chalk compaction from water weakening could be observed with 4D seismic. The new seismic survey, completed in 1999, indeed shows compaction-related differences when compared to the baseline 1989 seismic survey. Three main horizons are mappable on Ekofisk 3D seismic data. These are the top chalk reservoir, a tight zone separating the upper reservoir (Ekofisk formation) from the lower reservoir (Tor formation) and the base reservoir. The main 4D observation is a time shift of these main chalk horizons.

<p>Fluid extraction from subsurface reservoir sandstones frequently results in surface subsidence and induced seismicity, as observed in the Groningen Gas field (Netherlands). The cause lies in reservoir compaction driven by pressure depletion and the associated increase in effective overburden stress. Compaction in sandstones often includes elastic and significant inelastic components. The inelastic part is at least partly due to rate- or time-dependent processes, such as intergranular sliding or stress corrosion cracking. However, few mechanism-based rate/time-dependent compaction laws exist, despite the need to evaluate the impact of reservoir exploitation on field time scales (1-100 years). To help bridge this gap, we systematically investigated the effect of loading strain rate in the range from 10<sup>-3</sup> to 10<sup>-9</sup> s<sup>-1 </sup>in a series of triaxial compression experiments performed on water-saturated Bleurswiller sandstone samples with porosities of 21.07±0.15 % and composed of 66 % quartz, 28 % feldspar and 4 % clay. This material was chosen because of similarity to the Groningen sandstone but greater uniformity. We explored conditions of confining pressure (39 MPa), pore pressure (10 MPa) and temperature (100 °C) corresponding to in-situ values for Groningen. Axial strains up to 3 % were imposed. Our results showed combined elastic plus strain hardening (inelastic) loading behavior, up to a peak stress reached at 0.8-1.0 % strain, followed by strain softening towards a steady residual stress attained at 1.5-2.0 % strain. A systematic lowering of stress-strain curve levels was observed with decreasing strain rate, such that peak and residual stresses decreased respectively from 88 and 74 MPa at 10<sup>-3</sup> s<sup>-1</sup> to 70 and 61 at 10<sup>-9 </sup>s<sup>-1</sup>. No effect of loading rate is observed at differential stresses below ~ 50% of peak stress. At higher differential stresses up to peak, net sample stiffness (stress-strain curve slope) decreases with decreasing strain rate. Using the curve obtained at 10<sup>-3</sup> s<sup>-1</sup> as a reference, we determined the excess strains measured at rates of 10<sup>-4</sup> to 10<sup>-9</sup> s<sup>-1</sup> at fixed differential stresses up to the peak. By extrapolating this empirical relation to field strain rates associated with gas production in Groningen (i.e. 10<sup>-12</sup> s<sup>-1</sup>), it is estimated that ~30 % more compaction strain is developed under field conditions, at current differential stresses in the field (i.e. ~ 60 % peak stress), than in laboratory experiments at rates of 10<sup>-3</sup> to 10<sup>-5</sup> s-1. Additional experiments at varying temperature and confining pressure show sensitivities that suggest that the observed effect of strain rate is likely associated with a combination of time-dependent grain failure by stress corrosion and intergranular sliding. Work is in progress to assess the effect of varying mineralogy by conducting similar experiments on clay-free, quartz-rich Bentheimer sandstone. Our results show that time-dependent inelastic deformation plays an important role in estimating reservoir deformation and associated change in stress associated with fluid production from sandstone reservoirs, like the Groningen reservoir. Such effects could lead to underestimation of surface subsidence and induced seismicity, if not adequately accounted for. The present experiments thus provide important data for testing current models for rate-dependent reservoir compaction.   </p>

An improved understanding of flow behavior in older producing reservoirs, plus proactive reservoir management measures could lead to improving recovery efficiency. In this regard, one such measure is the use of time-lapse, multi-component seismic imaging to enhance the characterization of the reservoir's flow model. In this paper, we describe the application of this concept to a CO2 EOR project in Morrow sandstone in Postle field, Oklahoma, USA. Production and injection in the Morrow sandstone will cause saturation changes and can influence reservoir pressure based on operating practices. These changes, in turn, affect acoustic and elastic properties of rocks, which are detectable by time-lapse seismic imaging. Coupling these changes into flow simulation improves our understanding of the reservoir heterogeneity and connectivity. A reservoir simulation model was initially built using available geological, petrophysical and engineering data. The fluid flow performance was compared against observed reservoir performance. Time-lapse seismic anomalies, which are indicative of permeability variation in the reservoir, have been used to better understand reservoir connectivity and improve the quality of the reservoir model. On the other hand, flow simulation results help geophysicists to better interpret the time-lapse seismic anomalies. Results indicate that time-lapse seismic is capable of inferring the permeability field and can detect stratigraphic baffles in the reservoir. Additionally, it provides valuable inter-well information that can assist the history matching process and improve the quality of the reservoir model results. We also found out that although it is normally expected that the P-wave seismic anomalies show mainly the changes due to fluid saturation, our interpretation based on production / injection data and simulation study indicates that pressure changes can also affect the P-wave anomalies. Our research results demonstrate that dynamic reservoir characterization and integration of flow simulation and 4D seismic is a viable method for building an integrated reservoir model that can be used to guide field operations and maximize recovery efficiency.