Antonin Settari

Modeling the Propagation of Waterflood-Induced Hydraulic Fractures

A mathematical reservoir model is presented to simulate the propagation of waterflood induced hydraulic fractures in a symmetry element of a waterflood pattern. The model consists of a conventional single phase reservoir simulator coupled with an analytical fracture model. The model is capable of simulating fracture propagation as a function of (1) injection and production rates or pressures, (2) reservoir and fluid properties, and (3) formation fracturing pressures. Examples are given that clearly bring out the characteristics of the hydraulic fracture growth. The key variables are the injection rate and the voidage replacement ratio. Fractures can be contained by restricting the injection rate and by imposing a voidage replacement rate equal to or less than one.

Thermal Aspects of Geomechanics and Induced Fracturing in CO2 Injection With Application to CO2 Sequestration in Ohio River Valley

Ohio River Valley is considered a potential site for CO2 storage since it is in close proximity to large CO2 emitters in the area. In a CO2 storage project, the temperature of the injected CO2 is usually considerably lower than the formation temperature. The heat transfer between the injected fluid and rock has to be investigated in order to test the viability of the target formation to act as an effective storage unit and to optimize the storage process. A coupled flow, geomechanical and heat transfer model for the potential injection zone and surrounding formations has been developed. All the modeling focuses on a single well performance and considers induced fracturing for both isothermal and thermal injection conditions. The induced thermal effects of CO2 injection on stresses, displacements, fracture pressure and propagation are investigated. Possibility of shear failure in the caprock resulting from heat transfer between reservoir and the overburden layers is also examined. Displacements will be smaller for the thermal model compared to isothermal model. In the thermal case, the total minimum stress at the wellbore decreases with time and falls below the injection pressure quite early during injection. Therefore, fracturing occurs at considerably lower pressure for the thermal model. The coupled thermal and dynamic fracture model shows that thermal effects of injection could increase the speed of fracture propagation in the storage layer depending on the injection rate. These phenomena are dependent primarily on the difference between the injection and reservoir temperature. An optimization algorithm for injection temperature is discussed based on limiting the maximum fracture length and minimizing the risk of leakage from thermal effects of CO2 storage while improving the injection capacity. Incorporation of thermal effects in modeling of CO2 injection is significant for understanding the dynamics of induced fracturing in storage operations. Our work shows that the injection capacity with cold CO2 injection could be significantly lower than expected, and it may be impractical to avoid induced fracture development. In risk assessment studies inclusion of the thermal effects will help prevent the unexpected leakage in storage projects. The methodology developed will play an important role in process optimization for maximizing the injection capacity while maintaining the safety of storage. Introduction Ohio River Valley, located adjacent to the Mountaineer power plant in New Haven, West Virginia, is considered for saline aquifer geological storage of CO2. This valley is in a relatively stable, intraplate tectonic setting and the regional stress state is in strike slip to reverse faulting regime with the maximum stress oriented northeast to east-northeast. (Lucier et al, 2006). Based on current sequestration pilot projects and enhanced oil recovery efforts, evidence suggests that geologic sequestration is a technically viable means to significantly reduce anthropogenic emissions of CO2 (Solomon, 2006; Preston et al., 2005; Wright, 2007) Once CO2 is injected, the pressure and temperature of the formation is affected by the mass and heat transfer between the injected and in place fluid. These changes have geomechanical consequences on stresses, displacements, fracture pressure and its propagation. Since injected induced geomechanical effects could lead to formation or reactivation of fracture network, rock shear failure and fault movements which could potentially provide pathways for CO2 leakage, geomechanical modeling plays a very important role in risk assessment of geological storage of CO2.

The role of geomechanics in integrated reservoir modeling

The past decade has witnessed renewed interest and significant development in the field of reservoir geomechanics. Prior to that, geomechanics was a loosely collected group of applications of rock, soil, and fracture mechanics that addressed various problems in drilling, production, completion, and reservoir engineering. However, it is now increasingly evident that geomechanics is one of the common threads that connect many engineering disciplines that are essential for finding and producing hydrocarbon resources.

Coupled Numerical Modelling of Reservoir Flow with Formation Plugging

Permeability decline occurs during injection of produced water and seawater, resulting in injectivity declines and significant cost increases in waterflooding projects. It is necessary to have a reliable model to predict injectivity decline for preventive water treatment and waterflood design purposes. A classical deep bed filtration (DBF) model has been widely used to predict the injectivity decline. According to this model, the injectivity decline can be characterized by two empirical parameters: filtration coefficient, λ, and formation damage coefficient, β. Different methodologies developed to extract these parameters involve expensive and difficult concentration measurements, laboratory-scaled pressure drop measurements (not truly representative of the real reservoir) and simplifying assumptions of analytical solutions. A simple empirical velocity-based damage model proposed by Bachman et al. (1) is adopted in this work, and extended to multidimensional flow. This model is then compared to the deep bed filtration-based model. The advantage of the empirical model is that it can be easily tuned to either field or laboratory data, and can be easily implemented in reservoir simulators. The paper presents the formulation and numerical implementation of the two coupled reservoir flow and damage models. Different methods of implementing the velocity-based model in multidimensional flow are presented and evaluated. The comparison with the DBF model shows that the two models yield similar damage characteristics. Finally, application of the model to analysis of the published data for offshore Gulf of Mexico is presented. The relationship between the parameters of the two different approaches is validated for these case studies.

Coupled geomechanical and flow modeling of compacting reservoirs

The behavior of reservoir rocks that are subjected to varying stress regimes throughout the life of a producing field has major impact on critical aspects of development and production including (1) reservoir drive and depletion planning, (2) wellbore stability and integrity, and (3) subsidence and overburden deformation. The subdiscipline of geomechanics straddles a zone that overlaps the geosciences and engineering and includes the study of the mechanisms and consequences of various models of reservoir compaction. Coupling geomechanical modeling with classical reservoir simulation honors the links between changes in the internal stress field and flow properties—allowing us to better estimate the long-term behavior of producing reservoirs. This paper reviews some underlying aspects of coupled simulation and provides references for further study.

Thermal Effects on Shear Fracturing and Injectivity During CO2 Storage

With almost two hundred coal burning power plants in Ohio River valley, this region is considered important for evaluation of CO2 storage potential. In a CO2 storage project, the temperature of the injected CO2 is usually considerably lower than the formation temperature. The heat transfer between the injected fluid and rock has to be investigated in order to test the viability of the target formation to act as an effective storage unit and to optimize the storage process. In our previous work we have introduced the controversial idea of injecting CO2 for storage at fracturing conditions in order to improve injectivity and economics. Here we examine the thermal aspects of such process in a setting typical for Ohio River Valley target formation. A coupled flow, geomechanical and heat transfer model for the potential injection zone and surrounding formations has been developed. All the modeling focuses on a single well performance and considers induced fracturing for both isothermal and thermal injection conditions. The induced thermal effects of CO2 injection on stresses, and fracture pressure, and propagation are investigated. Possibility of shear failure in the caprock resulting from heat transfer between reservoir and the overburden layers is also examined. In the thermal case, the total minimum stress at the wellbore decreases with time and falls below the injection pressure quite early during injection. Therefore, fracturing occurs at considerably lower pressure, when thermal effects are present. The coupled thermal and dynamic fracture model shows that these effects could increase the speed of fracture propa‐ gation in the storage layer depending on the injection rate. These phenomena are dependent primarily on the difference between the injection and reservoir temperature.

Velocity-based Formation Damage Characterization Method for Produced Water Re-injection: Application on Masila Block Core Flood Tests

Abstract With increasing environmental regulations, more and more produced water is being re-injected; however, water injection programs may have low efficiency due to formation damage around the injected wellbore. Traditionally, formation damage was treated as a deep bed filtration (DBF) type of process characterized by laboratory-based damage parameters. These parameters inquire expensive concentration measurement, and lab-scaled results are not usually applicable for field cases. Recent studies on formation damage are more attracted to history-based approaches using an empirical damage equation to capture the uniqueness of each case study. In our previous work, such empirical (velocity based) model was studied and shown to be more practical than (and equivalent to) the DBF model. A robust characterization method was developed to calculate the damage parameters explicitly, and it was successfully tested against offshore field data. In this work, the method has been applied for analysis of a series of core flood tests on cores from the Masila Block field in Yemen and compared with measured damage parameters. Good agreement with lab-measured values validates the characterization method. The accuracy of the method is comparable to the DBF approach, while it is simpler and more suitable for implementing in reservoir simulators.

Numerical Techniques Used for Predicting Subsidence Due to Gas Extraction in the North Adriatic Sea

Abstract This article describes the assessment and application of numerical techniques required for predicting gas production induced subsidence in the North Adriatic. Due to the complexity of the reservoir description and compaction mechanisms, the subsidence modeling required the combined use of reservoir and geomechanical simulators. Extensive validation of the modeling techniques was undertaken, including the level of coupling between the fluid flow and geomechanical solution. It was shown that a fully coupled solution impacted only the aquifer area, and accurate results could be obtained by an explicitly coupled technique. Other issues of importance discussed include quality control of the mesh generation, mesh compatibility, and correct interpolation of variables between the two modules. Finally, we discuss the impact that small overconsolidation (threshold) effects may have on the extent of the subsidence bowl.

Characterization of the Pliocene Gas Reservoir Aquifers for Predicting Subsidence on the Ravenna Coast

Abstract The Pliocene reservoirs of the North Adriatic have produced gas since 1972. Several studies using reservoir and geomechanical models have been undertaken to quantify the surface land subsidence that may be attributed to pressure depletion resulting from gas production. Subsidence may continue after production ceases, as water influx repressures the depleted gas reservoirs, reduces the aquifer pressure, and causes the subsidence bowl to expand. Therefore, characterization of the Pliocene aquifers and water influx functions is important for long-term prediction of subsidence. An aquifer model was developed by integrating geological/geophysical interpretations, petrophysical data, and pressure/production data to describe the limited water influx observed in these reservoirs. The mechanism restricting water influx in the Pliocene gas reservoirs was found to be a combination of low effective permeability to water in the presence of clays and trapped gas saturation. The final aquifer model, which was validated with field pressure data, was used to predict long-term pressure drop in the aquifer for subsidence predictions.

Combined Reservoir Simulation And Seismic Technology, A New Approach For Modeling CHOPS

Cold Heavy Oil Production with Sand (CHOPS) has become one of the main recovery schemes for developing heavy oil reservoirs in Canada. This became possible with the introduction of progressive cavity pumps, therefore much higher sand cut in viscous heavy oil could be expected from unconsolidated/weakly consolidated formations as opposed to conventional pumps with limited capacity. In this study, combined reservoir simulation and seismic technology are applied for a heavy oil reservoir situated in Saskatchewan, Canada, for better understanding of the reservoir properties and recovery mechanism. The numerical model was built based on the well log data and several seismic attributes. The integration of seismic attributes improved modeling reservoir heterogeneity, which is a main challenge in modeling sand production. Firstly, we used geostatistical methods to estimate the initial reservoir porosity, using a seismic survey acquired in 1989. Secondly, sand production was modeled using erosional velocity approach and the model was run based on the oil production. Finally, results of the true porosity derived from simulation were compared against the porosity estimated from the second seismic survey acquired in 2001. This flow provides new tools that validate the simulation model results against the seismic data. Following this approach the extent and the shape of the enhanced permeability region (wormhole region) for estimated porosity distribution are modeled. The performance of the CHOPS wells is highly dependent on the rate of creation of the high permeability zone around the wells. This method can be used for evaluating future developments of the field such as infill drilling and post CHOPS recovery methods (VAPEX). Introduction Cold heavy oil production with sand (CHOPS) is a non-thermal recovery method used in unconsolidated heavy oil reservoirs in Alberta and Saskatchewan, Canada. In this process sand and oil are produced together in order to enhance the oil recovery. This process has proven to be economically successful when vertical wells are used. Although the process has been mostly developed in western Canada, it was first applied in California. Vonde (1957) reported that with the application of specially designed pumping equipment Husky Oil Co. was producing crude oil as low as 4 ° API with sand cuts of up to 70%. The wells were located in the Brooks sand, Cat Canyon field, California. Application of the progressive cavity pumps was a big step in improving oil rate of CHOPS. PCP pumps allowed primary production rates in excess of 150 bbl/d (24 m 3 /d) oil from wells that were restricted to less than 10 bbl/d (1.5 m 3 /d) when produced with conventional rod pumps and sand control completion methods. 2 SPE/PS/CHOA 117581 McCaffrey and Bowman (1991) examined the performance of Amoco’s Elk Point and Lindbergh fields in Canada. The program was to investigate the communication between wells using tracer material. Surprisingly the results indicated that wells were connected with a channel system exceeding over 2 km in length that connected up to 12 wells. There are two main mechanisms involved in unexpectedly high primary oil recovery observed in CHOPS operations. The first one is foamy oil associated with trapping gas evolution from in the heavy oil and the second one is sand production. McCaffrey and Bowman concluded the high productivity of CHOPS operations is related to three main factors: • Sand production creates an area around the wellbore which provided a larger effective wellbore drainage radius. This could be seen as a high negative skin effect in CHOPS wells. • Reduction in the in situ oil viscosity of the bitumen, as a result of foamy oil. • Increasing the porosity of the reservoir by producing sand which leads to creation of high permeability channels (wormholes). This improves the overall permeability of the reservoir. Sand Production Physics From geomechanics points of view there are two main mechanisms which could lead to sand production: • Shear failure, basically related to aggressive drawdown. This means that some plane in the near wellbore region is subjected to a higher shear stress than it can sustain. This may lead to a change of the near wellbore properties of the formation, and to a change in the near wellbore stresses • Tensile failure, basically related to high production rate. The sand production is then related to fluid drag forces on the grains of the formation. Tensile failure could also be resulted by foamy oil exsolution. Tremblay and Oldakowski (2002) performed two lab tests to investigate the wormhole growth. The used a sand box and they produce oil and sand from a perforation. In first test they only used one perforation. Later on they performed the second test where they used a larger sand pack (80.4 cm long and 29.85 cm diameter) than the one used in previous experiments (36.5 cm long and 10.2 cm diameter). In the second test they also had two production orifices (1.27 cm diameter), rather than the single orifice used in previous experiments (6.9 mm). The second test validates the first test results. Inside wormholes porosity was increased from the initial value of 36% to 55%. They observed that the wormhole was composed of a central region of loose sand surrounded by concentric bands. Based on the results of these tests they suggest that the diameter of wormholes in field could be as high as 1 m. Later on K. Oldakowski et al (2002) conducted a series of lab measurements at Alberta Research Council (ARC) to investigate the impact of stress anisotropy on wormhole growth. The results suggest that the wormholes are developed more toward the direction of the lower horizontal stress. Wong (2003) conducted a series of test to see the impact of the foamy oil and sand production in CHOPS. He studied the effects of the interlocked structure of oil sands, pressure gradient, and gas exsolution on sand production. Using a triaxial cell gave him the opportunity to apply confining stress on the sample. On his test with live oil he observed that sand production before reaching the bubble point in the outlet was not very significant. However as soon as the outlet presser was about 0.1 MPa below bubble point pressure significant amount of sand and foamy oil was produced. Wong concluded that the fact that heavy oil behave like cement around sand provides a high shear resistance against the seepage force generated by the fluid flow. However, he argues that the oil sand is very weak in resisting tensile failure under gas exsolution. Therefore he concluded that sand production is in most part due to the tensile stress because of the foamy oil. It should be noted that in Wong laboratory measurements he decreased the pressure very suddenly. The step change in pressure could cause the creation of cavity around the well and. This can bring some uncertainty and it suggests exaggeration of foamy oil impact in his test. SPE/PS/CHOA 117581 3 Sand Production Modeling Main challenges in modeling Cold production raised by high oil flow rates in field which are up to 10 times higher than the flow rates predicted by using Darcy’s flow equation. In Addition the oil recovery factor has also been reported to be significantly higher than predicted by Darcy’s flow models. Vardoulakis et al (1996) proposed hydro-erosion model, based on rigid porous media. In this theory mass balance is applied to a three-constituent system consisting of solid, fluid and fluidized solid using homogenization mixture theory. Wang (2003) extended this pure erosion model to include the effect of the deformation of porous media in a consistent manner. Based on Erosion modeling when the well is put on production after reaching critical velocity, the erosion process begins. Sand erosion is initiated by degradation of the sand matrix strength and the drag force imposed by fluid pressure gradient. Therefore locally around the wellbore the stress level became higher than the yielding stress and material erosion and stress re-distribution starts. Please see appendix section for explanations of the erosion model used in this study. Plover Lake Field History Plover Lake filed is a heavy oil reservoir currently operating by Nexen Inc. Plover Lake is situated in the heavy oil belt of Canada that extends over Alberta and Saskatchewan. Oil is produced from of the Devonian-Missippian Bakken Formation. This formations are found in NE-SW trending shelf-sand tidal ridges that can be up to 30 m thick, 5 km wide, and 50 km long. Overlying Upper Bakken shales are preferentially preserved between sand ridges. The Bakken Formation is disconformably overlain by Lodgepole Formation carbonates (Mississippian) and/or clastics of the Lower Cretaceous Mannville Group (Mageau et al., 2001). Figure 1 present the map of study area. Section 9 from township 35 and range 26 was selected for this study. Oil rate of different wells in this section range from 1 to 5 m 3 /d prior to installation of PCP pumps. After using PCP pumps oil rates increased 3 to 5 times, the majority of sand production has happened during this period. Unfortunately sand production measurements of individual wells were not available for this study. The cumulative sand production of wells suggests 30% to 60% initial sand cut which drops to 5% as oil rate declines. The initial seismic survey was performed on this field in 1989. The second seismic survey was done in 2001. Drilling spacing in this area is one well per LSD. Well 04-09 was selected for sand production modeling. Figure 1. Plover Lake CHOPS operation Map 4 SPE/PS/CHOA 117581