Zhu, Daoyi (China University of Petroleum, Beijing) | Hou, Jirui (China University of Petroleum, Beijing) | Wei, Qi (China University of Petroleum, Beijing) | Chen, Yuguang (China University of Petroleum, Beijing)
The PG Reservoir in Jidong Oil Field is at a depth of approximately 4500 m with an extremely high temperature of approximately 150°C. The average water cut has reached nearly 80%, but the oil recovery is less than 10% after only 2 years of waterflooding process. It is of great importance to develop a high-temperature-resistant plugging system to improve the reservoir conformance and control water production. An in-situ polymer-gel system formed by the terpolymer and a new crosslinker system was developed, and its properties were systematically studied under the condition of extremely high temperature (150°C). Suitable gelation time and favorable gel strength were obtained by adjusting the concentration of the terpolymer (0.4 to 1.0%) and the crosslinker system (0.4 to 0.7%). An increase of polymer and crosslinker concentration would decrease the gelation time and increase the gel strength. The gelant could form continuous 3D network structures and thus have an excellent long-term thermal stability. The syneresis of this gel system was minor, even after being heated for 5 months at the temperature of 150°C. The gel system could maintain most of the initial viscosity and viscoelasticity, even after experiencing the mechanical shear or the porous-media shear. Core-flow experiments showed that the gel system could have great potential to improve the conformance in Jidong Oil Field.
Several tools and techniques exist to understand distributions of reservoir properties. Interwell tracer testing is one of the most common methods to obtain reservoir information from the amount of tracer produced. The capacitance/resistance model (CRM) is an analytical tool to estimate connectivity between producer/injector pairs from historical rates and, when available, bottomhole-pressure data in waterfloods. Because the CRM is a physically based, simple input/output model, its combination with tracer testing can provide insight into reservoir features.
To enable the CRM application to tracer flow, we incorporated tracer models, based on miscible-displacement theory, into the CRM. Reservoir properties are estimated as a result of the model fitting to produced-tracer data. In this paper, we present three tracer models: a dispersion-only (short-range autocorrelation) model, a Koval (long-range) model, and a combination of the two. To incorporate the tracer models into the CRM, we used two methods, serial fitting (CRM then tracers) and simultaneous fitting (CRM and tracers).
We applied these techniques to tracer data from 10 injectors and 10 producers of the Lawrence Field. Results suggest that interwell connectivity obtained from the CRM is in good agreement with the observed peak-tracer concentrations. All tracer models are capable of giving a good fit in most of the cases. After comparing the tracer models, we determined that the combined model can represent a tracer flow better than the other two models alone. We also found that the simultaneous-fitting method gives the best fit to total producer-rate data and tracer data. Simultaneous fitting mitigates the nonuniqueness of the fits, leading to an improvement of tracer matching. The reservoir properties obtained in this study (Koval factor and dispersion coefficient) also were analyzed and compared with those from previous measurements.
Liu, Hui-Hai (Aramco Services Company) | Lai, Bitao (Aramco Services Company) | Zhang, Jilin (Aramco Services Company) | Huang, Xinwo (Aramco Services Company) | Chen, Huangye (Aramco Services Company)
This work proposes an innovative laboratory method to measure shale gas permeability as a function of pore pressure, a key parameter for characterizing and modeling gas flow in a shale gas reservoir. The development is based on a solution to 1D gas flow under certain boundary and initial conditions. The details of the theoretical background, including formulations to estimate gas permeability and conceptual design of the test setup, are provided. The advantages of our approach, surpassing the currently available ones, include that it measures gas permeability (as a function of pressure) with a single test run and without any presumption regarding the form of parametric relationship between gas permeability and pore pressure. In addition, our approach allows for estimating both shale permeability and porosity at the same time from the related measurements. Numerical experiments are conducted to verify the feasibility of the proposed methodology.
Kamal, Medhat M. (Chevron) | Morsy, Samiha (Chevron) | Suleen, F. (Chevron) | Pan, Yan (Chevron) | Dastan, Aysegul (Chevron) | Stuart, Matthew R. (Chevron) | Mire, Erin (Chevron) | Zakariya, Z. (Chevron)
A new method is presented that uses transient well testing to determine the in-situ absolute permeability of the formation when three phases of fluids are flowing simultaneously in the reservoir. The method was verified through simulation using synthetic data, and its applicability and practicality were confirmed through application to field data. Determining the absolute permeability over the reservoir scale using readily available transient testing data will have major benefits in accelerating history matching and improving reservoirperformance prediction.
A recently developed method (Kamal and Pan 2010) to determine the in-situ absolute permeability under conditions of two-phase flow extended the applicability of transient well testing and has been adopted in commercial software. In this study,
The method presented in this study uses surface flow rates and the fluid properties of the three phases. It also uses the same relative permeability relations used in the simulation models, thus ensuring that the same permeability values calculated from field data are used in history matching and predicting the performance of the reservoir. It is assumed that the fluid saturations are relatively uniform in the region around the well at the time of the transient test. The method was verified by comparing the input values with the results obtained from analyzing several synthetic tests that were produced by numerical simulation. Data from a deepwater field were also used to test the practicality and validity of the method. For the field case, the method was verified by matching reservoir production and pressure using the calculated absolute permeability. Excellent agreements were obtained for both synthetic and field cases.
AlAbbad, Mohammed A. (Saudi Aramco) | Sanni, Modiu L. (Saudi Aramco) | Kokal, Sunil (Saudi Aramco) | Krivokapic, Alexander (Institutt for Energiteknikk) | Dye, Christian (Institutt for Energiteknikk) | Dugstad, Øyvind (Restrack) | Hartvig, Sven K. (Restrack) | Huseby, Olaf K. (Restrack)
The single-well chemical-tracer test (SWCTT) is an in-situ test to measure oil saturation, and has been used extensively to assess the potential for enhanced oil recovery (EOR) or to qualify particular EOR chemicals and methods. An SWCTT requires that a primary tracer be injected and that a secondary tracer be generated from the primary tracer in situ. Typically, a few hundred liters of ester is injected as primary tracer, and the secondary tracer is formed through hydrolysis in the formations. The ester is an oil/water-partitioning tracer, whereas the in-situ-generated alcohol is a water tracer. During production, these tracers separate and the time lag of the ester vs. the alcohol is used to estimate oil saturation in the near-well region.
In this paper, we report a field test of a class of new reacting tracers for SWCTTs. In the test, approximately 100 cm3 of each of the new tracers was injected and used to assess oil saturation. In the test, ethyl acetate (EtAc) was used as a benchmark to verify the new tracers. This paper reviews the design and implementation of the test, highlights operational issues, provides a summary of the analyzed tracer curves, and gives a summary of the interpretation methodology used to find oil saturations from the tracer curves. Briefly summarized, we find the Sor measured by each of the novel tracers to compare with that from a conventional SWCTT. To validate stability and detectability of the tracers, a mass-balance assessment for the new tracers is compared with that of the conventional tracers.
A benefit of the new tracers is the small amount needed. Methodological advantages resulting from using small amounts include the possibility to inject a mix of several tracers. Using several tracers with different partitioning coefficients enables probing of different depths of the reservoir. In addition, the robustness of SWCTTs can be increased by using several tracers, with different reaction rates and temperature sensitivity. The field trial also demonstrated that the new tracers have operational advantages. One benefit is the possibility to inject the new tracers as a short pulse of 10 minutes. Other benefits are that the small amounts needed reduce operational hazards and ease logistical handling.
We introduce a novel well-logging method for determining more-accurate total porosities, fluid volumes, and kerogen volumes in shale-gas and shale-tight-oil wells. Improved accuracy is achieved by self-consistently accounting for the effects of light hydrocarbons and kerogen on the log responses. The logging measurements needed to practice this method are bulk densities, nuclear-magnetic-resonance (NMR) total porosities, and total-organic-carbon (TOC) weight fractions. The TOC weight fractions and the matrix densities, which are used to interpret the bulk density measurements, are both derived from geochemical-tool measurements.
Most unconventional shale-gas and shale-tight-oil reservoirs contain some nonproducible immobile hydrocarbons. When immobile hydrocarbons are present, our method requires prior knowledge of in-situ total water volumes. The water volumes can be estimated from dielectric-tool measurements. In special cases (e.g., in some mature shale-gas reservoirs) where no immobile hydrocarbons are present, a dielectric tool is not needed. In such cases total water volumes are outputs of the method.
We discuss the response functions in shale reservoirs for measurements of bulk densities, NMR porosities, and TOC weight fractions and derive exact self-consistent solutions to the response equations. The algebraic solutions are used to compute shale total porosities, fluid volumes, and kerogen volumes. The predicted shale total porosities and fluid volumes are corrected for light-hydrocarbon effects on the measured bulk densities and NMR porosities and for kerogen effects on the bulk densities. It is shown that significant errors can be made in log-derived shale total porosities if NMR porosities or density-log porosities are assumed to represent true-shale porosities without applying proper corrections.
We discuss the application of the method to the analysis of logging data acquired in a mature shale-gas well drilled in the Marcellus Shale in the northeastern United States and to data acquired in a shale-tight-oil well drilled in the Permian Basin in west Texas. A multifrequency dielectric tool is used to determine in-situ total water volumes in the tight oil well. The mature shale-gas reservoir does not contain immobile hydrocarbons, and, therefore, dielectric-logging measurements were not needed in this well. The results in both wells are shown to compare favorably with core data.
The volume of hydrocarbons contained in tight petroleum reservoirs is immense. Thus, their development is crucial to satisfy the worldwide energy demand. A critical aspect for the development of these formations is the stress dependency of rock properties. As pore pressure changes, porosity, permeability, and compressibility of both matrix and natural fractures in tight reservoirs also change, affecting the wells’ production behavior.
A practical problem in the estimation of stress-dependent properties is that the amount of core data available to perform the corresponding studies in tight formations is generally scarce. Under these circumstances, drill cuttings can be used to obtain this information. These observations lead to the key objective of this paper: to develop a reliable approach for estimating stress-dependent properties through the introduction of an innovative methodology that quantifies changes in properties of tight reservoirs and how to extend this methodology in drill cuttings.
The model developed is based on the relationship between the cube root of normalized permeability and the logarithm of net confining stress defined as confining pressure minus pore pressure applied on the rock. An empirical exponent α is introduced to fit the experimental data from confining tests conducted on both vertical and horizontal core samples. This exponent allows the development of an equation that works independently of the initial net confining stress, which is the main limitation of the models already available in the literature. It is our experience that, in many instances, laboratory tests are run at specific values of net confining stress that do not necessarily match the current stress of the reservoir. The correlation proposed in this paper is valuable because it provides a tool that allows correcting the laboratory results to the appropriate net confining stresses in the reservoir. A statistical analysis is performed to verify the appropriateness of the proposed model for the prediction of rock properties as a function of net confining stress.
It is shown that current formulations are particular cases of the proposed model based on the results obtained for the empirical exponent α. Semilog cross-plots of the cube root of normalized permeability versus the net confining stress using core laboratory data corroborate the robustness of the proposed method. The application of the method with drill cuttings is also demonstrated.
It is concluded that the proposed method provides a more accurate methodology for estimating stress-sensitive properties of rocks in tight formations, which are usually naturally fractured, such as the Nikanassin formation analyzed in this work. Porosity, permeability, and compressibility of tight formations are estimated by following the generalized methodology proposed in this study.
Brown, Joel (Chevron Corp) | Kumar, Raushan (Chevron Corp) | Barge, David Lee (Chevron Corp) | Lolley, Christopher (Chevron Corp) | Lwin, Al (Chevron Corp) | Al-Ghamdi, Saleh (Chevron Corp) | Bartlema, Ruurd (Chevron Corp) | Littlefield, Brian (Chevron Corp)
The 1st Eocene is a multibillion-barrel heavy-oil carbonate reservoir in Wafra field in the Partitioned Zone (PZ) between the Kingdom of Saudi Arabia and Kuwait. A large-scale steamflood pilot has been successfully completed in the 1st Eocene reservoir. The large-scale pilot (LSP) was the first multipattern steamflood in a carbonate reservoir in the Middle East, and consisted of sixteen 2.5-acre inverted 5-spot patterns with associated steamflood and production facilities. The primary objective of the LSP was to identify and mitigate technical and economic risks and uncertainties in carbonate steamflooding to assist in the broader Wafra full-field steamflood development (FFSFD) decisions. The key technical uncertainties related to the steamflooding in 1st Eocene reservoir were identified, categorized, and prioritized. These were then used as a basis to create surveillance and subsurface response plans. Success measures were developed to assess success in steamflooding this carbonate reservoir. These success measures were derived from the key metrics that were prerequisites for the FFSFD. The pilot met all the success measures, thereby mitigating the key technical uncertainties, and opened the path to FFSFD. This paper describes the elements of pilot planning and the results achieved during pilot execution. The emphasis, specifically, is on the achievements against the success measures set for the project; the insights into the pilot behavior from detailed analysis of production, pressure, and temperature data; and the progress made in identifying and mitigating key uncertainties in carbonate steamflooding.
The geomechanical properties of reservoirs, which are important for formation stimulation, are often determined from triaxial tests on large-scale samples such as core plugs or blocks. It is difficult to recover large samples from shale formations because they are mechanically unstable and usually break down into pieces. The present study develops a two-scale model that uses drill cuttings to estimate the static elastic properties of shales at the core scale. We first propose a physically representative element to capture the elastic deformation of a solid grain with a known minerology by accounting for the grain size and its elastic properties using the structural-mechanics approach (a small-scale model). We then develop a core-scale model dependent on the volume fractions of the minerals, which are obtained from X-ray diffraction (XRD), for different realizations of the spatial distribution of the solid grains (large-scale model). The sensitivity of the large-scale model to the number of the elements is tested. The proposed model shows promising results for four shale formations (New Albany, Rocky Mountain Siliceous, Lower Bakken, and Barnett) and has major applications for the geomechanical characterization of a formation from drill cuttings.
This paper documents the formation of natural fractures in the Horn River Group, a major Canadian shale gas play, and addresses relationships between natural-fracture development and rock-mechanical properties derived from cores and well logs. Most natural fractures in the Horn River Shale are narrow vertical fractures, sealed with carbonate minerals. In this study, the formation of observed fractures is primarily determined by a lithology type, mineral composition, and rock-mechanical properties at the timing of fracturing.
Brittleness is an important geomechanical property controlling the formation of fractures, because brittle shale is more easily fractured than ductile shale, and fractures in brittle shale tend to persist when the fracturing pressure is released. In this study, a hardness value measured by a commercial hardness tester is found to be a good proxy for the brittleness of shale layers. On the basis of a statistical analysis, the threshold values of both hardness and brittleness are estimated to predict the distribution of natural fractures, assuming that the mechanical properties of the host rock were relatively stable from at least the time at which fractures formed. Hardness values are shown to be more reliable than brittleness.