TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractOil recovery operations are seeing increased use of integrated geomechanical and reservoir engineering to help manage fields.This trend is partly a result of newer, more sophisticated measurements that are demonstrating that variations in reservoir deliverability are related to interactions between changing fluid pressures, rock stresses and flow parameters such as permeability. Several recent studies, for example, have used finite-element models of the rock stress to complement the standard reservoir simulation.We discuss current work on fully coupling the geomechanical elastic/plastic rock stress equations to a commercial reservoir simulator.This finite difference simulator has black-oil, compositional and thermal modes and all of these are available with the geomechanics option. In this paper, the focus is on the implementation of the stress equations into the code. Some work on benchmarking against an industry standard stress code is also shown as well as an example of the coupled stress/fluid flow. Our goal in developing this technology within the simulator is to provide a stable, comprehensive geomechanical option that is practical for large-scale reservoir simulation.
A reliable, non-conservative assessment of the risk of solids production is essential in order to identify the optimal completion strategy. A technique for such an assessment is developed in this paper through a geomechanical study of the Everest Complex of the North Sea, involving wells 22/10a-T2 and 22/10a-T6. This process is based on calibrating depth indexed measurements at discrete points using core data. The core samples were selected to be representative of the complete range of porosities and various clay volumes throughout the reservoir. The first step is the construction of the reservoir mechanical model by combining geophyscial well logs, the results of laboratory tests on core samples, and other field data, particularly drilling histories. In the second step, critical calibrated using predictions determined at single points using an elastoplastic theory (Bradford and Cook 1) which incorporates the influences of plastic hardening and delation. Results calculated using a new elastic-perfectly plastic model, which is derived in this paper, are also included. This model is suitable for use with log data. Results have been verified by simulating production through a perforation with thick wall cylinder tests on whole core form 22/10a-T2 (Nicholson et al.10). The results of the modelling provide formation failure data to build a map of the sanding potential in the Everest reservoirs. P. 261
A geomechanics option that features the three dimensional elastoplastic stress equations which are fully or partly coupled to a commercial reservoir simulator is applied to a field and a synthetic case. Sanding, fracturing and stress dependent flow are analysed. First the basic formulation is discussed. Elastic stress equations and boundary conditions are described including their implementation in the finite difference simulator. Comparison is made with an industry standard finite element code with an option for coupled single phase flow. It is demonstrated that the finite difference implementation of the stress equations, which is second order, can produce acceptable accuracy when compared against finite element simulators. Non-orthogonal corner-point gridding is also reviewed in this context when the gridding is skewed. Some features of other gridding types including unstructured grids are also presented. Plasticity, stress dependent permeability and faults are available as options. Two cases are presented which were designed to demonstrate the applications of sand management, simulation of tight gas reservoirs with stress dependent permeability and propped/etched fractures. The sand management case is based on an offshore gas field. Reservoir geometry, properties and geological (tectonic) details were provided by the operator. A case which simulates fracturing was designed as a tutorial. Although synthetic, it offers a workflow for the use of predicted stress and pore pressure as input to calculations of fracture conductivities/geometries whose output is returned to the simulator. This geomechanics option is currently under development. Some areas of further work are mentioned. Introduction The topic of coupled stress and fluid flow has received much attention recently in the literature. Koutsabeloulis and Hope1 discuss two couplings of fluid flow and rock stress. The first involves coupling a finite element stress analysis simulator with a streamline fluid flow simulator. A second method is to calculate a fully coupled solution of these equations within the finite element simulator. Coupling to other reservoir simulators is also possible. It is stated that there may be substantial differences when running uncoupled versus coupled flow simulations, although the fully coupled finite element flow simulation took no account of stress directionality, magnitude and neglected discontinuities in the rock. A second case shows differences in bottom hole pressure (BHP) at a well with and without including a stress analysis. With a stress calculation, the observed change in time of the BHP was qualitatively predicted, without it the trends predicted by the stand-alone flow simulator were almost opposite. Settari and Mourits2 and Settari and Walters3 analyse different degrees of modular coupling. Decoupled systems can be solved, firstly, with the reservoir model only, where the compressibility must be modified to account for the expected type of containment (free deformation or laterally constrained).Secondly, a reservoir simulation prediction of the entire time history of pressure can then be used to compute a transient stress solution. Coupled predictions were classified as explicit, in which the coupling is lagged by a timestep, iterative in which a repeated solution of the flow and stress equations takes place during the timestep or fully in which the full system of equations is solved simultaneously. Comparisons were made of predictions with linear and nonlinear elastic models. Aspects of plasticity and thermoporoelasticity were discussed. Chin, Raghavan and Thomas4 also discuss a fully coupled finite element implementation. Yale5 gives an overview of many aspects of coupling, referring to some of the pioneering work of Biot6 and Terzaghi7 as well as the more recent work of Gutierrez8.The same coupled geomechanics-fluid flow finite element method in Reference 1 was used to investigate critical state constitutive modeling, elastic-plastic effects, stress path effects and permeability alteration. Tran, Settari and Nghiem9 explore a new iterative coupling by examining in detail the porosity formulation.
Keshen reservoir is a deep, tight gas sandstone reservoir under high tectonic stress with reservoir pressure over 16,000 psi (110 MPa) and temperatures up to 165 °C. Development wells for this field are in excess of 6500m in true vertical depth. Stimulation is required to provide production rates that compensate for the high cost of drilling and completing wells. Hydraulic fracture design and execution must be optimal to ensure economic production. To effectively stimulate a more than 200 m thick sandstone reservoir with consistently high performance, it is necessary to understand the mechanical behaviour of the reservoir, especially mechanical properties and in-situ stresses as the two control initiation and propagation of each hydraulic fracture. The mechanical behaviour is complicated by high tectonic stresses, significant compaction, and high overpressure. To gain an in-depth understanding of the mechanical properties and in-situ stresses of Keshen reservoir, an integrated geomechanical evaluation was conducted. The evaluation used core from two wells, KS205 and KS207, and log data obtained from 15 wells including the wells with core evaluation in the field. A laboratory testing program to investigate the mechanical behavior of the reservoir sandstone under realistic in-situ stresses, pore pressures, and temperature was performed. The description of mechanical behavior obtained from the laboratory testing was used to calibrate and augment mechanical earth models (MEMs) constructed from well log data. The reliability of the completed MEMs was validated through comparison between wellbore stability predictions with observation of borehole failure from the borehole microresistivity image. The geomechanics information was delivered to the stimulation engineering team. Hydraulic fracture design and execution was conducted based on this information. The outcome of hydraulic fracturing was very encouraging. This study demonstrated that successful stimulation of tight reservoir in high pressure, high temperature relies on integrated geomechanical analysis.
An experimental study was conducted on the mature Messla field to investigate the mechanism of fines migration and its contribution in formation damage. In the study, an advanced laboratory test programme was designed after investigation of production history, well performance, in-situ stress state and depletion history. The programme included critical velocity tests and pore volume Compressibility (PVC) fines migration tests. The critical velocity tests investigated the relationship between flow rate and decrease of permeability by flowing the core plug at different flow rate and concurrently measuring corresponding permeability. Additionally, alternating flow of kerosene and formation water was conducted in the tests to investigate the effect of water breakthrough on fines migration. The PVC fines migration tests were carried out by applying triaxial loading to the samples that followed the stress path of reservoir depletion to identify any critical depletion level that may damage the formation during reservoir production. Concurrently, horizontal flow measurements were made with the PVC tests to simulate production. In addition, produced fines were evaluated by using standard light microscope and Scanning Electron Microscopy (SEM). The composition of any fines collected is further identified through X-Ray Diffraction (XRD) analysis. Through these tests, the tendency and severity of fines migration in this field were investigated and the impact of reservoir depletion on permeability was revealed. Based on the knowledge, the sandface completions were optimized to improve their performance. Introduction The giant Messla field is located in the southeast portion of Sirte Basin in Libya, approximately 500 km southeast from Benghazi.1 The field, operated by AGOCO, has been producing since the year 1971. Currently, production decline has been observed from many wells in this field. It was recognized that to address production decline in the field, a comprehensive investigation had to be conducted to delineate the major contributing factors. Understanding the mechanism of fines migration and its contribution to formation damage is an essential aspect of the study. Once understood, remedies such as acidization or fines stabilization can be applied to effectively address formation damage and improve production. Furthermore, the knowledge will also provide pertinent guidance on the design of sandface completions to address the sanding issues in the field.1 Literature review indicated that formation fines are ubiquitous in oil- and gas-bearing sandstones,2,3,4,5 especially in unconsolidated materials.6 Fines migration generally refers to small solid, unattached particles of sand and/or clay which have become dislodged, entrained in the flowing fluids and transported through the porous formation towards the well. During migration, fines can bridge pore throats and restrict fluid movement.7 This process can severely damage the formation as well as sandface completions,8,9,10,11,12 thereby causing devastating effect on the productivity of wells or reservoirs. In the last 30 years, different attempts have been made to address fines migration and related formation damage.3,6,12,13,14,15,16,17,18,19 To address the problems of production decline in the Messla field, an investigation of fines migration and its involvement in formation damage was regarded as essential. A key finding of previous investigations in the industry is that there is a critical velocity or flow rate, below which entrainment of fines does not occur, and above which the rate of entrainment increases linearly with flow rate.5,7,8,11,13,17,20,21 Therefore, it is often observed from a flowing test that at initial low flow rate, the permeability of the core sample remains constant but once the flow rate increases to a critical level, there is sharp decrease in permeability. In this study, critical velocity tests were conducted to determine if fines migration is an issue in the production of Messla reservoir sandstone and if so, at what production rates, fines migration would become an issue.
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