Relative permeability (kr) functions are among the essential data required for the simulation of multiphase flow in hydrocarbon reservoirs. These functions can be measured in the laboratory using different techniques including the steady state displacement technique. However, relative permeability measurement of shale rocks is extremely difficult mainly because of the low/ultralow matrix permeability and porosity, dominant capillary pressure and stress-dependent permeability of these formations.
In this study, the impacts of stress and capillary end effects (CEE) on the measured relative permeability data were investigated. The steady state relative permeability (SS-kr) measurements were performed on Eagle Ford and Pierre shale samples. To overcome the difficulties regarding the kr measurements of shale rocks, a special setup equipped with a high-pressure visual separator (with an accuracy of 0.07 cc) was used. The kr data were measured at different total injection rates and liquid gas ratios (LGR). In addition, to evaluate the impacts of effective stress, the kr data of an Eagle Ford shale sample were measured at two different effective stresses of 1000 and 3000 psi.
From the experimental data, it was observed that the measured SS-kr data of the shale samples have been influenced by the capillary end effects as the data showed significant variation when measured at different injection rates (with the same LGR). This suggested that the liquid hold-up (i.e. capillary end effects) depends on the competition of capillary and viscous forces. In addition, it was shown that it is more necessary to correct the experimental kr data measured at the lower LGRs. Furthermore, different relative permeability curves were obtained when the kr data were measured at different effective stresses. This behavior was explained as the capillary pressure was expected to be more dominant at the higher effective stress.
The results from this study improve our understanding of unconventional mechanisms in shale reservoirs. It is evident that the behavior of unconventional reservoirs can be better predicted when more reliable and accurate relative permeability data are available. The outcomes of this study will be useful for accurate determination of such kr data.
Many gas reservoirs at the appraisal stage exhibit evidence of persistent gas saturations below free water levels (FWL's). The amounts of gas contained here may, under some situations, be a sizable fraction of the gas cap volumes. Many engineers appear poorly equipped to include, and model, paleo gas in simulation models. This often results in paleo gas being simply ignored when development plans are being considered. This is unfortunate because paleo gas upon pressure depletion can expand, displacing brine towards well completions. This means that while some additional gas production may occur from the paleo zone, the risk of water production may be significantly underestimated if paleo gas is simply omitted. This work discusses the evidence for paleo gas and shows that it may be described and incorporated in simple simulation models provided the user avoids some common misconceptions. It is demonstrated that under depletion conditions, paleo gas can be entirely visible to material balance pressure responses, while at the same time increasing the risk of produced water volumes. For higher pressure paleo gas reservoirs the common P on Z diagnostic plots can also provide early trends that are frequently misinterpreted. This work quantifies the curvature that can result in such systems, and shows that simulation models inherently predict the expected curvature in P on Z. The approach taken here is by design simplistic and is applicable to scoping evaluations where the paleo gas volumes could be a significant volumetric uncertainty. Where possible, we indicate where additional, or more rigorous, descriptions can be applied.
As active oil reservoirs mature, marginal fields development and management is becoming increasingly important.
Early identification of high degree reservoir heterogeneity served as starting point for an in-depth analysis for both, geologist and reservoir engineer.
This paper describes complex approach applied during evaluation and development of marginal oil field "Is" located in Serbia (Pannonian Basin).
Effective transition from exploration to development took place in 3 stages.
I-stage: 1 exploration well drilled, detailed analysis (seismic, sedimentology, core, PVT) and interpretation (log, well-test). Identification of vertical heterogeneity led to detailed analysis, which resulted in local depositional environment theory. Integration of seismic attribute and sedimentological analysis results was done. Due to geological uncertainties several 3D models were done for STOIIP range estimation. Recovery factor range was estimated using statistical, analytical and simulation model approach.
II-stage: 1 exploration well and 1 development well drilling and detailed analysis update.
III-stage: drilling of 5 development wells and continuous update of geological and simulation models.
Major uncertainties identified during I-stage were regarding to: reservoir structure, vertical and lateral heterogeneity, major fault permeability and OWC depth. Additionally, existence of active aquifer affected recovery factor estimation range.
I-stage analysis showed that, depending on depositional environment 4 different rock types are presented by conglomerates, conglo-breccia, breccia and metamorphic rocks.
The target formation (conglomerates) were formed by proluvial fan. This deposits are characterized by an alternation of rhythms (fragment size and orientation, conglomerate size, terrigenous material sorting).
Proluvial fan boundaries were detected on the seismic attribute map.
Second exploration well location was a result of multidisciplinary analysis during I-stage. Well was successful and highly informative during II-stage as it proved oil saturation behind major fault, reduced previous STOIIP estimates and confirmed presence of active aquifer.
STOIIP and reservoir structure excluded possibilities for regular/typical well patterns, therefore each well location was carefully selected, while total well number was determined based on estimated recovery factor.
Complex multidisciplinary approach used during this project, can be an example for successful and effective marginal heterogeneous oil field development. Understanding the reasons for reservoir heterogeneity together with confident estimate of recovery factor, gave us success during each new well placement and total well number determination.
Al-Bayati, Duraid (Curtin University) | Saeedi, Ali (Kirkuk University) | Ghasemi, Mohsen (Curtin University) | Arjomand, Eghan (Curtin University) | Myers, Mathew (Curtin University) | White, Cameron (CSIRO-Energy) | Xie, Quan (CSIRO-Energy)
Carbon dioxide (CO2) injection has been identified as an important means to achieve hydrocarbon reservoir potential whilst mitigating the greenhouse gas effect. CO2 injection into depleted oil reservoirs is very often accompanied by chemical interactions between the formation rock and in situ formed solute. Sandstone formations were expected to contain less reactive minerals in their composition, compared with carbonate counterparts. However, the evolution of petrophysical parameters may change due to different clay content in different sandstone rocks. In this manuscript, we evaluate possible petrophysical parameter evolution in layered sandstone core sample during miscible CO2 water alternating gas (WAG) injection. The stratified core sample is composed of two axially split half sandstone plugs each with different permeability. Grey Berea, Bandera Brown, and Kirby sandstone were used to represent low, moderate and high clay content, respectively. Core flooding experiments were conducted using CO2, brine (7 wt % NaCl + 5 wt % KCl + 5 wt % CaCl2.2H2O) and
The results showed a reasonable increase in the post-flood porosity about 1.0% as a maximum. The results also revealed that the changes in porosity are correlated reasonably with the clay minerals amount in the sample (i.e. higher clay mineral amount leads to higher evolution). The X-ray CT images and NMR results confirmed changes in pore spaces and pore size distribution across the core sample. These changes possibly attributed to clay minerals migration which released by mineral dissolution and subsequent pore throat plugging. NMR results also revealed that the larger the pore size, accompanied by high clay mineral amount, the higher the evolution. This may be attributed to the higher contact surfaces at these pores with the injected CO2 (in-situ formed carbonic brine).
Our results provide insight into how clay content may affect CO2/sandstone reaction in the presence of permeability/mineralogy heterogeneity. In addition, it highlights the control of clay content on rock petrophysical parameter evolution, thus its significance in modelling CO2 injection in sandstone reservoirs.
Gao, Jia Jia (Department of Civil & Environmental Engineering, National University of Singapore) | Lau, Hon Chung (Department of Civil & Environmental Engineering, National University of Singapore) | Sun, Jin (Institute of Deep-sea Science and Engineering, Chinese Academy of Sciences)
Conventional drilling design tends to inaccurately predict the mud density needed for borehole stability because it assumes that the porous medium is fully saturated with a single fluid while in actuality it may have two or more fluids.
This paper provides a new semi-analytical poroelastic solution for the case of an inclined borehole subjected to non-hydrostatic stresses in a porous medium saturated with two immiscible fluids, namely, water and gas. The new solution is obtained under plane strain condition. The wellbore loading is decomposed into axisymmetric and deviatoric cases. The time-dependent field variables are obtained by performing the inversion of the Laplace transforms. Based on the expansion of Laplace transform solution, we derive the unsaturated poroelastic asymptotic solutions for early times and for a small radial distance from an inclined wellbore. The model is verified by analytical solutions for the limiting case of a formation saturated with a single fluid. The impact of unsaturated poroelastic effect on pore pressure, stresses and borehole stability is investigated.
Our results show that the excess pore pressure due to the poroelastic effect is generally higher for the saturated case than the unsaturated case due to the large difference between the compressibility of fluid phases. The time-dependency of the poroelastic effect causes the safe mud pressure window of both the unsaturated and saturated cases to narrow with increasing time with the unsaturated case giving a narrower safe mud pressure window. Furthermore, this window narrows with increasing initial gas saturation. The commonly used assumption that the formation is fully saturated by one fluid tends to be conservative in predicting the mud density required for borehole stability.
This new semi-analytical poroelastic solution enables the drilling engineer to more accurately estimate the time-dependent stresses and the pore pressure around a borehole, thus allowing him to design the mud weight to ensure borehole stability.
Faster, lower-cost measures of multiphase permeability of conventional reservoirs are promised by a digital rock analysis method developed by BP and Exa, which is marketing software to measure relative permeability. This paper describes the development of “digital-rocks” technology, in which high-resolution 3D image data are used in conjunction with advanced modeling and simulation methods to measure petrophysical rock properties.
The author writes that the generally accepted Knudsen diffusion in shales is based on a mistranslation of the flow physics and may give theoretically unsound predictions of the increased permeability of shales to gas flow. An extensive laboratory study was carried out with two objectives: to evaluate the effect of water quality on injectivity of disposal wells with reservoir core plugs and to restore injectivity of damaged wells. The F field in the Middle East currently has more than 40 producing wells in the center of the structure. The uneven well distribution limits the understanding of 3D reservoir characterization, particularly in the flank areas.
This course is intended for those who are very familiar with reservoir evaluation and development concepts for conventional reservoirs but who are interested in learning more about the unique technologies applied to shale and tight reservoirs. Recent success in developing oil from very low permeability reservoirs in North America has sparked global interest in how these plays are being identified, evaluated and developed. This course addresses these issues that require unique approaches, as compared to conventional oil reservoirs, primarily in the areas of well design, hydraulic fracture design, log analysis, core analysis and production forecasting. This course is intended for engineers, geologists, and technical support staff. All cancellations must be received no later than 14 days prior to the course start date.
Specic experiments have been designed and the experimental measurements obtained show that, not only the absolute permeability but also the gas relative permeability are sensitive to connement and that the residual gas saturation (through permeability "jail") increases with loading. This observation represents an additional source of complexity in the evaluation of low-permeability sandstone gas reservoirs. INTRODUCTION Low-permeability sandstone gas reservoirs, also called tight reservoirs, are generally considered stress-sensitive reservoirs. Numerous laboratory tests under single-phase ow have shown that the absolute permeability of these reservoir rocks decreases strongly with connement. This dependence on connement is attributed to the existence of joints and interfaces in tight rocks, which close when loading increases, as pointed out by Walsh and Brace (1984) and Warpinski and Teufel (1992).
Massive hydraulic fracturing requires an enormous consumption of water and introduces many potential environmental issues. In addition, water-based fluid tends to be trapped in formations, reducing oil/gas-phase relative permeability, and causes clay-mineral swelling, which lowers absolute permeability. Carbon dioxide (CO2) is seen as a promising alternative working fluid that poses no formation-damage risk, and it can stimulate more-complex and extensive fracture networks. However, very little, if any, extant research has quantitatively analyzed the effectiveness of CO2 fracturing, except for some qualitative fracturing experiments that are based on acoustic emissions. In this study, we systematically examine water and CO2 fracturing, and compare their performance on the basis of a rigorously coupled geomechanics and a fluid-heat-flow model. Parameters investigated include fluid viscosity, compressibility, in-situ stress, and rock permeability, illustrating how they affect breakdown pressure (BP) and leakoff, as well as fracturing effectiveness. It is found that (1) CO2 has the potential to lower BP, benefiting the propagation of fractures; (2) water fracturing tends to create wider and longer tensile fractures compared with CO2 fracturing, thereby facilitating proppant transport and placement; (3) CO2 fracturing could dramatically enhance the complexity of artificial fracture networks even under high-stress-anisotropy conditions; (4) thickened CO2 tends to generate simpler fracture networks than does supercritical CO2 (SC-CO2), but still more-complex fracture networks than fresh water; and (5) the alternative fracturing scheme (i.e., SC-CO2 fracturing followed by thickened-CO2 fracturing) can readily create complex fracture networks and carry proppant to keep hydraulic fractures open. This study reveals that, for intact reservoirs, water-based fracturing can achieve better fracturing performance than CO2 fracturing; however, for naturally fractured reservoirs, CO2 fracturing can constitute an effective way to stimulate tight/shale oil/gas reservoirs, thereby improving oil/gas production.