Showing papers in "Spe Reservoir Evaluation & Engineering in 2007"

Preformed Particle Gel for Conformance Control: Transport Mechanism Through Porous Media

Abstract: Preformed particle gel (PPG) has been successfully synthesized and applied to control excess water production in most of the mature, waterflooded oil fields in China. This paper reports on laboratory experiments carried out to investigate PPG transport mechanisms through porous media. Visual observations in etchedglass micromodels demonstrate that PPG propagation through porous media exhibits six patterns of behavior: direct pass, adsorption, deform and pass, snap-off and pass, shrink and pass, and trap. At the macroscopic scale, PPG propagation through porous media can be described by three patterns: pass, broken and pass, and plug. The dominant pattern is determined by the pressure change with time along a tested core (as measured at specific points), the particle-size ratio of injected and produced particles from the core outlet, and the residual resistance factor of each segment along the core. Measurements from micromodel and routine coreflooding experiments show that a swollen PPG particle can pass through a pore throat with a diameter that is smaller than the particle diameter owing to the elasticity and deformability of the swollen PPG particle. The largest diameter ratio of a PPG particle and a pore throat that the PPG particle can pass through depends on the swollen PPG strength. PPG particles can pass through porous media only if the driving pressure gradient is higher than the threshold pressure gradient. The threshold pressure depends on the strength of the swollen PPG and the ratio of the particle diameter and the average pore diameter.

Preformed Particle Gel for Conformance Control: Factors Affecting Its Properties and Applications

Abstract: Preformed particle gel (PPG) is a particled superabsorbent crossklinking polymer that can swell up to 200 times its orginal size in brine. The use of PPG as a fluid-diverting agent to control conformance is a novel process designed to overcome some distinct drawbacks inherent in in-situ gelation systems. This paper introduces the effect of gelant compositions and reservoir environments on the two properties of PPG: swollen gel strength and swelling capacity. Results have shown that PPG properties are influenced by gelant compositions, temperature, brine salinity, and pH below 6. Temperature increases PPG swelling capacity but decreases its swollen gel strength. Salinity decreases PPG swelling capacity but increases its swollen gel strength. PPG is thermostable at an elevated temperature of 120°C if a special additive agent is added into its gelant as a composition. PPG is strengthand sizecontrolled, environmentally friendly, and not sensitive to reservoir minerals and formation water salinity. Two field applications are introduced to illustrate the criteria of well candidate selection and the design and operation process of PPG treatments. Field applications show that PPG treatment is a cost-effective method to correct permeability heterogeneity for the reservoirs with fractures or channels, both of which are widely found in mature waterflooded oil fields.

Finite Element - Node-Centered Finite-Volume Two-Phase-Flow Experiments With Fractured Rock Represented by Unstructured Hybrid-Element Meshes

Abstract: Fractured-reservoir relative permeability, water breakthrough, and recovery cannot be extrapolated from core samples, but computer simulations allow their quantification through the use of discrete fracture models at an intermediate scale. For this purpose, we represent intersecting naturally and stochastically generated fractures in massive or layered porous rock with an unstructured hybrid finite-element (FE) grid. We compute two-phase flow with an implicit FE/finite volume (FV) method (FE/FVM) to identify the emergent properties of this complex system. The results offer many important insights: Flow velocity varies by three to seven orders of magnitude and velocity spectra are multimodal, with significant overlaps between fractureand matrix-flow domains. Residual saturations greatly exceed those that were initially assigned to the rock matrix. Total mobility is low over a wide saturation range and is very sensitive to small saturation changes. When fractures dominate the flow, but fracture porosity is low (10 to 1%), gridblock average relative permeabilities, kr,avg, cross over during saturation changes of less than 1%. Such upscaled kr,avg yield a convex, highly dispersive fractionalflow function without a shock. Its shape cannot be matched with any conventional model, and a new formalism based on the fracture/matrix flux ratio is proposed. Spontaneous imbibition during waterflooding occurs only over a small fraction of the total fracture/matrix-interface area because water imbibes only a limited number of fractures. Yet in some of these, flow will be sufficiently fast for this process to enhance recovery significantly. We also observe that a rate dependence of recovery and water breakthrough occurs earlier in transient-state flow than in steady-state flow.

Modeling Laboratory Permeability in Coal Using Sorption-Induced Strain Data

Abstract: Sorption-induced strain and permeability were measured as a function of pore pressure using subbituminous coal from the Powder River basin of Wyoming, USA, and high-volatile bituminous coal from the Uinta-Piceance basin of Utah, USA. We found that for these coal samples, cleat compressibility was not constant, but variable. Calculated variable cleat-compressibility constants were found to correlate well with previously published data for other coals. Sorption-induced matrix strain (shrinkage/swelling) was measured on unconstrained samples for different gases: carbon dioxide (CO2), methane (CH4), and nitrogen (N2). During permeability tests, sorption-induced matrix shrinkage was demonstrated clearly by higher-permeability values at lower pore pressures while holding overburden pressure constant; this effect was more pronounced when gases with higher adsorption isotherms such as CO2 were used. Measured permeability data were modeled using three different permeability models that take into account sorption-induced matrix strain. We found that when the measured strain data were applied, all three models matched the measured permeability results poorly. However, by applying an experimentally derived expression to the strain data that accounts for the constraining stress of overburden pressure, pore pressure, coal type, and gas type, two of the models were greatly improved.

Production-Data Analysis of Single-Phase (Gas) Coalbed-Methane Wells

Abstract: The current work illustrates how single-well production-data-analysis (PDA) techniques, such as type curve, flowing material balance (FMB), and pressure-transient (PT) analysis, may be altered to analyze single-phase CBM wells Examples of how reservoir inputs to the PDA techniques and subsequent calculations are modified to account for CBM-reservoir behavior are given This paper demonstrates, by simulated and field examples, that reasonable reservoir and stimulation estimates can be obtained from PDA of CBM reservoirs only if appropriate reservoir inputs (ie, desorption compressibility, fracture porosity) are used in the analysis As the field examples demonstrate, type-curve, FMB, and PT analysis methods for PDA are not used in isolation for reservoir-property estimation, but rather as a starting point for single-well and multiwell reservoir simulation, which is then used to history match and forecast CBM-well production (eg, for reserves assignment) To study the effects of permeability anisotropy upon production, a 2D, single-phase, numerical CBM-reservoir simulator was constructed to simulate single-well production assuming various permeability-anisotropy ratios Only large permeability ratios ({lt} 16:1) appear to have a significant effect upon single-well production characteristics Multilayer reservoir characteristics may also be observed with CBM reservoirs because of vertical heterogeneity, or in cases where the coals are commingled with conventionalmore » (sandstone) reservoirs In these cases, the type-curve, FMB, and PT analysis techniques are difficult to apply with confidence Methods and tools for analyzing multilayer CBM (plus sand) reservoirs are presented Using simulated and field examples, it is demonstrated that unique reservoir properties may be assigned to individual layers from commingled (multilayer) production in the simple two-layer case« less

Implications of Coupling Fractional Flow and Geochemistry for CO2 Injection in Aquifers

Abstract: The geochemical changes caused by CO2 injection into aquifers include acidification and carbonation of the native brine and potential mineral dissolution and precipitation reactions driven by the aqueous composition changes. The latter are important for evaluating the potential CO2 storage capacity in the form of minerals and can also influence the performance of the injection well. The theories of geochemical flows and of fractional flow provide useful insight into several aspects of CO2 sequestration. This paper gives the mathematical formalism of combined geochemical and multi-phase flow. If local equilibrium applies, the theory leads to graphical solution, from which it is easy to see when and under what conditions mineralization will occur during the injection. The theory also illustrates the influence of post-injection flow on mode of CO2 trapping (hydrodynamic, solubility, mineral, residual saturation). We also show that co-injection of water significantly alters the mode of trapping. Introduction Carbon dioxide sequestration was first discussed in the late 1970s. However, serious research and development in CO2 sequestration only began in the early 1990s. The technical literature28 about CO2 disposal in aquifers includes feasibility studies in The Netherlands and in the Alberta Basin, Canada. A field test is being performed in the North Sea in the Sleipner Vest project, which is the first CO2 sequestration project in a brine-bearing formation. Sequestering CO2 in geologic formations offers numerous advantages, including: (1) The experience of the oil industry can directly provide the technology to enable the commercialization of this approach. (2) Several collateral economic benefits are possible, for example, enhancing oil and gas recovery while storing CO2. (3) Suitable geologic formations, including oil, gas, brine, and coal formations are relatively easy to find. (4) The regulatory infrastructure associated with the injection into oil and gas formations and deep aquifers is well established. (5) Geologic analogs such as natural CO2 reservoirs prove that geologic structures can sequester CO2 for a very long time. (6) Public acceptance for geologic sequestration should grow as technological advances lead to innovative methods for creating permanent mineral sinks for CO2. Carbon dioxide can be sequestered in geologic formations by three principal mechanisms. (1) CO2 can be trapped as a gaseous phase or supercritical fluid under a low-permeability caprock, similar to what occurs in natural gas reservoirs (hydrodynamic trapping). (2) Dissolution into an aqueous phase (solubility trapping). (3) CO2 can react with the minerals and the organic matter in geologic formations to become a part of the solid (mineral trapping). Formation of carbonate minerals such as calcite or siderite and the adsorption onto coal are other examples of the mineral trapping. Mineral trapping will create stable repositories of CO2 that decrease mobile hazards such as leakage to the surface. An additional form of storage -as a residual gas saturation -is also studied in this and a companion paper. Here CO2 remains as a gaseous phase, such as hydrodynamic trapping, but it is immobile because the gas is trapped by capillary forces. In this study, the immobile gas trapping is called the residual saturation trapping. Siliciclastic aquifers should have greater potential for the mineral trapping of CO2 compared to carbonate aquifers. Depending on whether the basic aluminosilicate minerals, such as feldspars, zeolites, illites, chlorites and smectites, contain an alkali or alkaline earth cation, two types of mineral trapping can be considered. Na/K-bearing minerals result in the development of bicarbonate brines. Fe/Ca/Mg-bearing minerals result in the precipitation of siderite, calcite or

Geomechanical Effects on the SAGD Process

Abstract: Steam-assisted gravity drainage (SAGD) is a robust thermal process that has revolutionized the economic recovery of heavy oil and bitumen from the immense oil-sands deposits in western Canada, which have 1.6 to 2.5 trillion bbl of oil in place. With steam injection, reservoir pressures and temperatures are raised. These elevated pressures and temperatures alter the rock stresses sufficiently to cause shear failure within and beyond the growing steam chamber. The associated increases in porosity, permeability, and water transmissibility accelerate the process. Pressures ahead of the steam chamber are substantially increased, promoting future growth of the steam chamber. A methodology for determining the optimum injection pressure for geomechanical enhancement is presented that allows operators to customize steam pressures to their reservoirs. In response, these geomechanical enhancements of porosity, permeability, and mobility alter the growth pattern of the steam chamber. The stresses in the rock will determine the directionality of the steam chamber growth; these are largely a function of the reservoir depth and tectonic loading. By anticipating the SAGD growth pattern, operators can optimize on the orientation and spacing of their wells. Core tests are essential for the determination of reservoir properties, yet oil sand core disturbance is endemic. Most core results are invalid, given the high core-disturbance results in test specimens. Discussion on the causes and mitigation of core disturbance is presented. Monitoring of the SAGD process is central to understanding where the process has been successful. Methods of monitoring the steam chamber are presented, including the use of satellite radar interferometry. Monitoring is particularly important to ensure caprock integrity because it is paramount that SAGD operations be contained within the reservoir. There are several quarter-billion-dollar SAGD projects in western Canada that are currently in the design stage. It is essential that these designs use a fuller understanding of the SAGD process to optimize well placement and facilities design. Only by including the interaction of SAGD and geomechanics can we achieve a more complete understanding of the process.

A Review on Recent Advances in the Numerical Simulation for Coalbed-Methane-Recovery Process

Abstract: The recent advances in numerical simulation for primary coalbed methane (CBM) recovery and enhanced coalbed-methane recovery (ECBMR) processes are reviewed, primarily focusing on the progress that has occurred since the late 1980s. Two major issues regarding the numerical modeling will be discussed in this review: first, multicomponent gas transport in in-situ bulk coal and, second, changes of coal properties during methane (CH{sub 4}) production. For the former issues, a detailed review of more recent advances in modeling gas and water transport within a coal matrix is presented. Further, various factors influencing gas diffusion through the coal matrix will be highlighted as well, such as pore structure, concentration and pressure, and water effects. An ongoing bottleneck for evaluating total mass transport rate is developing a reasonable representation of multiscale pore space that considers coal type and rank. Moreover, few efforts have been concerned with modeling water-flow behavior in the coal matrix and its effects on CH{sub 4} production and on the exchange of carbon dioxide (CO{sub 2}) and CH{sub 4}. As for the second issue, theoretical coupled fluid-flow and geomechanical models have been proposed to describe the evolution of pore structure during CH{sub 4} production, instead of traditional empirical equations. However,more » there is currently no effective coupled model for engineering applications. Finally, perspectives on developing suitable simulation models for CBM production and for predicting CO{sub 2}-sequestration ECBMR are suggested.« less

Improved Characterization and Modeling of Capillary Transition Zones in Carbonate Reservoirs

Abstract: An oil/water capillary transition zone often contains a sizable portion of a field’s initial oil in place, especially for those carbonate reservoirs with low matrix permeability. The field-development plan and ultimate recovery may be influenced heavily by how much oil can be recovered from the transition zone. This in turn depends on a number of geological and petrophysical properties that influence the distribution of initial oil saturation (Soi) against depth, and on the rock and fluid interactions that control the residual oil saturation (Sor), capillary pressure, and relative permeability characteristics as a function of initial oil saturation. Because of the general lack of relevant experimental data and the insufficient physical understanding of the characteristics of the transition zone, modeling both the static and dynamic properties of carbonate fields with large transition zones remains an ongoing challenge. In this paper, we first review the transition-zone definition and the current limitations in modeling transition zones. We describe the methodology recently developed, based on extensive experimental measurements and numerical simulation, for modeling both static and dynamic properties in capillary transition zones. We then address how to calculate initial-oil-saturation distribution in the carbonate fields by reconciling log and core data and taking into account the effect of reservoir wettability and its impact on petrophysical interpretations. The effects of relative permeability and imbibition capillary pressure curves on oil recovery in heterogeneous reservoirs with large transition zones are assessed. It is shown that a proper description of relative permeability and capillary pressure curves including hysteresis, based on experimental special-core-analysis (SCAL) data, has a significant impact on the field-performance predictions, especially for heterogeneous reservoirs with transition zones.

Prediction of Three-Phase Relative Permeabilities Using a Pore-Scale Network Model Anchored to Two-Phase Data

Abstract: A first attempt has been made to predict three-phase relative permeability experimental data of a water-wet Berea sandstone obtained by Oak using the three-phase flow network model for arbitrary wettability developed by van Dijke and Sorbie. First, the network model is anchored to the corresponding two-phase relative permeability and capillary pressure data using an idealised representation of the pore geometry and a simple parameter fitting procedure. Then, predictions of three-phase properties are made, which are compared with experimental data as well as previous predictions from a different network models. The present study has confirmed that the relatively simple network model, anchored to experimental data, is able to predict three-phase relative permeabilities with reasonable accuracy, comparable to the accuracy using more complex models. Based on these preliminary results a limited sensitivity study is carried out with respect to different wettability states and two combinations of interfacial tensions. This study reveals some new results with respect to the invariance of relative permeability to interfacial tension combinations and the trend of water relative permeability as a function of the fraction of oil-wet pores in systems of non-uniform wettability. Introduction Relative permeabilities in a three-phase system depend not only on phase saturations, but also on the saturation history and may be further complicated by wettability effects. Empirical correlations, which were designed to predict threephase relative permeabilities from more readily available twophase data (e.g. Stone), are not capable of reproducing this complex behaviour. Alternatively, network models predict the three-phase relative permeabilities, by simulating the flow processes based on the details of pore space representation, fluids and pore scale flow mechanisms. Existing network model formulations vary from simple bond models with idealised pore geometries to complex models with a detailed geometrical representation of the reconstructed 3D pore space. Theoretically, a more detailed representation of the porous medium and the flow processes should provide a better approximation of the macroscopic flow behaviour and better predictive capabilities. On the other hand, measuring all the detailed pore-scale parameters, as well as modelling these features, is clearly impossible. Many studies report predictions of two-phase relative permeabilities (e.g. Refs. 5 and 6) but relatively few attempts have so far been made to predict three-phase properties. Recently, two network model studies have been published predicting three-phase experimental data of Oak. Both studies are based on the stochastically reconstructed threedimensional microstructure of Berea sandstone. To reduce the computational cost of solving the transport equations, the detailed microstructure was converted into a pore network with a simplified pore and throat geometry, which was supposed to preserve all relevant features of the reconstructed pore space. Additionally, both networks incorporate a detailed explicit description of intra-pore fluid configurations. Because the above models have been conditioned to a particular rock no further adjustment of network parameters is needed. Both networks additionally incorporate a detailed explicit description of the intra-pore fluid configurations and distinguish between receding and advancing contact angles. For a simulation of the water-oil imbibition the latter were randomly distributed between 10-30 and 30-80. Predicted twoand three-phase relative permeabilities of both studies are in reasonable agreement with experimental data. Additionally, Piri and Blunt have made a first attempt to model three-phase relative permeabilities in mixed-wet systems. Oak also measured three-phase relative permeabilities for a mixed-wet sandstone, modelling of which is another important and more difficult challenge. In the present study we also model the experimental results of Oak, who reported for a relatively simple and well defined water-wet system two-phase oil-water and gas-oil capillary pressures, drainage and imbibition relative permeabilities, as well as a three-phase data set including saturation paths and corresponding relative permeabilities for a wide range of saturation histories. First, we present a summarised description of the network model, followed by a description of the experimental data. Then, we present “anchoring” of the network model by matching the water-oil

New Method of Incorporating Immobile and Non-vaporizing Residual Oil Saturation Into Compositional Reservoir Simulation of Gasflooding

Abstract: Summary In compositional simulation of gas-injection processes, it is often observed that gridblock oil saturations decrease far beyond the user-defined residual oil saturation, even under immiscible conditions. This numerical phenomenon occurs because oil components are allowed to vaporize into the gas phase as much as the phase equilibrium obtained with an equation of state (EOS) permits. Especially in the vicinity of gas injectors, an oil saturation of zero is sometimes predicted. On the other hand, such significant low oil saturation is rarely seen in laboratory data such as coreflood experiments and slimtube tests. The reason for the discrepancy between the simulation results and the laboratory results described above is that bypassed oil located in dead-end pores or caused by subgrid-scale heterogeneities is not considered in the current compositional-simulation practice. To overcome this, we developed an innovative method of incorporating laboratory-based residual oil saturations. The proposed method can restrict the excessive vaporization and maintain the prescribed residual oil by accommodating a novel application of the transport coefficient (Barker and Fayers 1994).