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.
Controlled laboratory experiments and some field studies have shown that the onset of sand production in gas wells differs from that in oil wells. Results from a general 3D sand-production numerical model are presented to explain the differences in the onset of sanding and sand-production volume for different fluids and under different flow and in-situ stress conditions. The sand-production model accounts for multiphase-fluid flow and is fully coupled with an elasto-plastic geomechanical model. The sanding criterion considers both mechanical failure and sand erosion by fluid flow. Non-Darcy flow is implemented to account for the high flow rates. The drag forces on the sand grains are computed on the basis of the in-situ Reynolds number. Both the intact rock strength and the residual rock strength depend on water saturation. Water evaporation (drying) resulting from gas flow is modeled using phase equilibrium calculations.
The onset of sand production is compared for different fluid types (oil and gas). Model results are shown to be consistent with experimental observations reported in the literature. For example, the onset of sanding is observed at higher compressive stresses for gas wells as compared with oil wells. The primary mechanism for this is for the first time shown to be sand strengthening induced by evaporation of water. This effect is not observed in oil wells. The sand-production rate when non-Darcy effects are considered is lower than for Darcy flow. The reason for this is the lower fluid velocity (for the same drawdown) and, consequently, smaller drag forces on the failed sand grains. The effect of water breakthrough and water cut on sand production is studied from both mechanical and erosion perspectives. The model is shown to be capable of accurately predicting the onset of sanding and sand production induced by multiphase- and compressible-fluid flows, helping us to predict sanding issues in both oil and gas wells.
Yoneda, Jun (National Institute of Advanced Industrial Science and Technology) | Takiguchi, Akira (West Japan Engineering Consultants) | Ishibashi, Toshimasa (West Japan Engineering Consultants) | Yasui, Aya (West Japan Engineering Consultants) | Mori, Jiro (West Japan Engineering Consultants) | Kakumoto, Masayo (National Institute of Advanced Industrial Science and Technology) | Aoki, Kazuo (National Institute of Advanced Industrial Science and Technology) | Tenma, Norio (National Institute of Advanced Industrial Science and Technology)
During gas production from offshore gas-HBS, there are concerns regarding the settlement of the seabed and the possibility that frictional stress will develop along the production casing. This frictional stress is caused by a change in the effective stress induced by water movement caused by depressurization and dissociation of hydrate as well as gas generation and thermal changes, all of which are interconnected. The authors have developed a multiphase-coupled simulator by use of a finite-element method named COTHMA. Stresses and deformation caused by gas-hydrate production near the production well and deep seabed were predicted using a multiphase simulator coupled with geomechanics for the offshore gas-hydrate-production test in the eastern Nankai Trough. Distributions of hydrate saturation, gas saturation, water pressure, gas pressure, temperature, and stresses were predicted by the simulator. As a result, the dissociation of gas hydrate was predicted within a range of approximately 10 m, but mechanical deformation occurred in a much wider area. The stress localization initially occurred in a sand layer with low hydrate saturation, and compression behavior appeared. Tensile stress was generated in and around the casing shoe as it was pulled vertically downward caused by compaction of the formation. As a result, the possibility of extensive failure of the gravel pack of the well completion was demonstrated. In addition, in a specific layer, where a pressure reduction progressed in the production interval, the compressive force related to frictional stress from the formation increased, and the gravel layer became thin. Settlement of the seafloor caused by depressurization for 6 days was within a few centimeters and an approximate 30 cm for 1 year of continued production.
Chen, Xin (BGP) | Wang, Guihai (CNODC) | Wang, Zhaofeng (CNODC) | Liu, Zundou (CNODC) | Liu, Zhaowei (CNODC) | Cui, Yi (CNODC) | Tian, Wenyuan (CNODC) | Wei, Xiaodong (BGP) | Hou, Liugen (BGP) | Yang, Ke (BGP) | Chen, Gang (BGP) | Xia, Yaliang (BGP) | Yan, Xiaohuan (BGP) | Zhang, Zeren (BGP) | Liu, Jingluan (BGP)
To improve the accuracy of permeability prediction, seismic constraint and sedimentary facies has often been adopted in conventional methods. However, it is porosity that both of them constrain, rather than permeability, and different pore structure with different permeability, the accuracy of permeability prediction cannot be radically improved. To address the problem of permeability prediction in carbonate reservoir, new permeability prediction technique workflow were summarized based on pore structure analysis and multi-parameters seismic inversion: division reservoir types based on the pore structure, construction of the rock types identification curve, carry out a rock type inversion and a porosity inversion constrained by seismic impedance respectively, and then get a final permeability prediction volume according to the porosity-permeability relationship and pore structure of core samples. It breaks the bottleneck that is difficult for seismic impedance (continuous variable) to constrain rock type (discrete variable), then constrains pore structure (continuous variable) related to rock type instead, and converts it into rock type using multi-parameters seismic inversion. According to the certification of new wells, this workflow have been applied successfully in carbonate reservoir of H oilfield in Middle East, it not only improves the prediction of rock type in space, but also permeability prediction accuracy.
Geo-modelling is usually done to honor static data such as core, well logs and seismic acoustic impedance (AI) map where available. Once the static geo-model is complete, history matching is carried out by tuning the static model properties until the model reproduces observed dynamic behavior. The objective of this paper is to showcase how a systematic a priori integration of dynamic elements into geo-modelling eliminated the need for history matching. These dynamic elements are; connected reservoir regions CRR (
CRRs were defined based on time-lapse shut-in pressure trend groups. Core and log data were grouped on the basis of the identified CRR and used to build CRR-based Neural Network models for predicting permeability logs of non-cored wells within each CRR. The geo-modeler then created two geo-realizations by using the permeability logs within each CRR to distribute permeability within the CRR using two assumptions of variogram lengths (i) variogram range obtained from analysis of limited core data, (ii) variogram range required to ensure intra-CRR connectivity. Pressure transient was simulated for wells with observed PTA data using the two realizations, and a comparison of the log-log plots of simulated pressure transient derivative and observed pressure transient derivative were used to determine the quality of each realization for each well. The realization that provided the least squares of error across all the wells was selected as base-case geo-model. Permeability correction coefficients were applied on the base-case geo-model until PTA kh were acceptably matched. The resulting permeability log at the PTA well is referred to as PTA-corrected permeability log. Some cored wells were originally exempted from the neural-network permeability modelling because they didn't have logs (sonic, density and neutron logs). Hybrid permeability logs were derived from a combination of the predicted permeability logs and core permeability at these well locations.
All permeability correction logs (i) PTA-corrected permeability logs and (ii) Hybrid permeability logs were then fed back into the geo-modeling workflow to generate an improved permeability distribution which respects core data, PTA kh, and CRRs.
The do-nothing simulation run has more than 80% of wells’ pressure data acceptably history matched. This application demonstrates that a priori integration of dynamic elements like CRR, PTA kh, and the use of CCR-based permeability modeling results in a better characterized geo-model with potential for eliminating the need for history matching.
The oil price has fallen off dramatically since 2014 which quenched the oil company's enthusiasm to develop new oil fields, especially those with low quality reservoir. For Bohai oilfield, its work is mainly focused on the mature oilfield development in view of its huge reservoir potential, convenient existing facilities and quick fund turnover period. Bohai oilfield has carried out several projects to keep production steady at 3000×104m3 for eight years. In the paper, several methods including high resolution seismic acquisition, potential sands tracking, improving oil recovery (IOR) by water flooding and nanoparticle profile controlling are presented.