Integrated fracture characterization of Asmari reservoir in Haftkel field

The Asmari reservoir in Haftkel field is one of the most prolific naturally fractured reservoirs in the Zagros folded zone in the southwest of Iran. The primary production was commenced in 1928 and continued until 1976 with a plateau rate of 200,000 bbl/day for several years. There was an initial gas cap on the oil column. Gas injection was commenced in June 1976 and so far, 28% of the initial oil in place have been recovered. As far as we concerned, fracture network is a key factor in sustaining oil production; therefore, it needs to be characterized and results be deployed in designing new wells to sustain future production. Multidisciplinary fracture evaluation from well to reservoir scale is a great privilege to improve model’s accuracy as well as enhancing reliability of future development plan in an efficient manner. Fracture identification and modeling usually establish at well scale and translate to reservoir using analytical or numerical algorithms with the limited tie-points between wells. Evaluating fracture network from production data can significantly improve conventional workflow where limited inter-well information is available. By incorporating those evidences, the fracture modeling workflow can be optimized further where lateral and vertical connectivity is a concern. This paper begins with the fracture characterization whereby all available data are evaluated to determine fracture patterns and extension of fracture network across the field. As results, a consistent correlation is obtained between the temperature gradient and productivity of wells, also convection phenomenon is confirmed. The findings of this section help us in better understanding fracture network, hydrodynamic communication and variation of temperature. Fracture modeling is the next step where characteristics of fractures are determined according to the structural geology and stress directions. Also, the fault’s related fractures and density of fractures are determined. Meanwhile, the results of data evaluation are deployed into the fracture model to control distribution and characteristics of fracture network, thereby a better representation is obtained that can be used for evaluating production data and optimizing development plan.

Field-Scale Modeling of Smart Completion Tools for Optimum Recovery

Flow control devices (FCDs) like inflow control devices (ICDs) and interval control valves (ICVs) (i.e., equalizer) have increased applications in both conventional and unconventional resources. They have been used to mitigate water or gas coning problems for mature fields in conventional reservoirs, to alleviate premature water breakthrough in naturally fractured reservoirs, and to optimize the steam distribution in heavy oil reservoirs. There have been increased trend in using FCDs in the real field. Previously, complex well models have been implemented in a large-scale parallel reservoir simulator by Tareq et al. (2017). The implementation can simulate an intelligent field contains tens to hundreds of multilateral complex wells commonly referred in the literature as maximum reservoir contact (MRC) wells with mechanical components such as ICVs and ICDs. In this paper, a new framework to model controlling the FCDs in complex well applications will be presented. The implementation is integrated into a complex well model. It can be easily used to model the dynamical control of devices. Simulation studies using both sector model and field model have been conducted. A systematic full-field operation is used for device control applications of smart wells. Successful application of field level controls in smart wells has the benefit of the improved overall GOSP performance.

Evaluation of Foam-Gels for Conformance Control in High Temperature High Salinity Carbonates

In naturally fractured reservoirs, conformance control prior to enhanced oil recovery (EOR) application might be essential to ensure optimal contact and sufficient sweep. Recently, few studies investigated combining foams and gels into what is commonly coined as foamed-gels. Foamed-gels have been tested and shown to be potential for some field conditions. Yet, very limited studies were performed for high temperature and high salinity carbonates. Therefore, in this work, we study the potential of foamed-gels for high temperature and high salinity carbonates. The objective is to evaluate the potential of such synergy and to compare its value to the individual processes. For that purpose, in this work, we rely on bulk and core-scale tests. Bulk tests were used for initial screening. Wide range of foam-gel solutions were prepared with different polymer types and polymer concentrations. Test tubes were hand shacked thoroughly to generate foams. Foam heights were then measured from the test tubes. Heights were used to screen foaming agents and to study gelant effects on foamers in terms of foam strength (heights). The effect of foamers on gelation was evaluated through bottle tests. Based on the results, an optimal concentration ratio of gelant to foamer was determined and used in core-scale displacements, to further study the potential of this hybrid foam-gel process. Bulk results suggested that addition of the gelant up to a 4:1 foam to gel concentration ratio resulted in sufficient foam generation in some of the polymer samples. Yet, only two of the foam-gel samples generated a strong gel. Increasing the foamer concentration delayed the gelation time and in some samples, the solution did not gel. Through the coreflooding experiment, resistance factor (RF) and residual resistance factor (RRF) were obtained for different conformance control processes including foam, foam-gel, and gel. Foam-gel injection exhibited higher RF and RRF values than conventional foams. However, conventional gels showed even higher RF and RRF values than foam-gels. Combining two of the most widely used conformance control methods (foams and gels) can strike a balance. Foam-gel may offer a treatment that is deeper and more sustainable than foams and on the other a treatment that is more practical, and lower-cost than gels. Our laboratory results also demonstrate that such synergetic conformance control can be achieved in high salinity and high temperature carbonates with pronounced impact.

Predicting the Productivity Enhancement After Applying Acid Fracturing Treatments in Naturally Fractured Reservoirs Utilizing Artificial Neural Network

Acid fracturing treatments are conducted to increase the productivity of naturally fractured reservoirs. The treatment performance depends on several parameters such as reservoir properties and treatment conditions. Different approaches are available to estimate the efficacy of acid fracturing stimulations. However, a limited number of models were developed considering the presence of natural fractures (NFs) in the hydrocarbon reservoirs. This work aims to develop an efficient model to estimate the effectiveness of acid fracturing treatment in naturally fractured reservoirs utilizing an artificial neural network (ANN) technique. In this study, the improvement in hydrocarbon productivity due to applying acid fracturing treatment is estimated, and the interactions between the natural fractures and the induced ones are considered. More than 3000 scenarios of reservoir properties and treatment parameters were used to build and validate the ANN model. The developed model considers reservoir and treatment parameters such as formation permeability, injection rate, natural fracture spacing, and treatment volume. Furthermore, percentage error and correlation coefficient were determined to assess the model prediction performance. The proposed model shows very effective performance in predicting the performance of acid fracturing treatments. A percentage error of 6.3 % and a correlation coefficient of 0.94 were obtained for the testing datasets. Furthermore, a new correlation was developed based on the optimized AI model. The developed correlation provides an accurate and quick prediction for productivity improvement. Validation data were used to evaluate the reliability of the new equation, where a 6.8% average absolute error and 0.93 correlation coefficient were achieved, indicating the high reliability of the proposed correlation. The novelty of this work is developing a robust and reliable model for predicting the productivity improvement for acid fracturing treatment in naturally fractured reservoirs. The new correlation can be utilized in improving the treatment design for naturally fractured reservoirs by providing quick and reliable estimations.

Conditions of the Formation Gas Deposits in the Epart of the Dnieper-Donets Basin: Integration of Basin Modeling Data with Consequences of Strike-Slip Faulting Effects

Since 1950, when the megascale Shebelinka deposit was found in the north-eastern portion of the Dnieper-Donets basin (DDB) this district has been served as a heartland of the hydrocarbon extraction in Ukraine. Right now, this area is again facing a new wave of commercial interest. Most conventional hydrocarbon plays here contain natural gas and liquid gas accumulated in numerous clastic and fractured horizons throughout Carboniferous to Lower Permian successions. The numerical basin modelling in the Donbas segment indicated that organic-rich sediments are thermally mature in the deep levels of the basin. Our interpretation of the structural patterns within the study area suggests that the kinematic development of the fracture sets is consistent with the model of development of subsidiary structures within the dextral strike-slip zone. Nearly all gas and gas condensate fields in the eastern part of the DDB may be classified as naturally fractured reservoirs in fault-breached anticlinal traps associated with releasing jogs in strike-slip assemblages. Gaseous hydrocarbons generated in deep "gas window" compartments have escaped here via several fracture corridors forming "sweet spots " sites. The main objective of this contribution is to get an insight into the style and structural trends of formation structural traps of hydrocarbons which in concert with basin modeling technologies will ensure proper technical decisions for the efficient exploration and production of gas reservoirs. This research summarizes new insights into gas deposits formation in the eastern part of DDB based on a synthetic approach ascertaining a vital connection of basin modeling results with the spatial distribution of kinematically induced releasing jogs which facilitating magnified fluid-and-gas conductivity.

A Cut-Cell Polyhedral Finite Element Model for Coupled Fluid Flow and Mechanics in Fractured Reservoirs

Mechanical deformation induced by injection and withdrawal of fluids from the subsurface can significantly alter the flow paths in naturally fractured reservoirs. Modeling coupled fluid-flow and mechanical deformation in fractured reservoirs relies on either sophisticated gridding techniques, or enhancing the variables (degrees-of-freedom) that represent the physics in order to describe the behavior of fractured formation accurately. The objective of this study is to develop a spatial discretization scheme that cuts the "matrix" grid with fracture planes and utilizes traditional formulations for fluid flow and geomechanics. The flow model uses the standard low-order finite-volume method with the Compartmental Embedded fracture Model (cEDFM). Due to the presence of non-standard polyhedra in the grid after cutting/splitting, we utilize numerical harmonic shape functions within a Polyhedral finite-element (PFE) formulation for mechanical deformation. In order to enforce fracture-contact constraints, we use a penalty approach. We provide a series of comparisons between the approach that uses conforming Unstructured grids and a Discrete Fracture Model (Unstructured DFM) with the new cut-cell PFE formulation. The manuscript analyzes the convergence of both methods for linear elastic, single-fracture slip, and Mandel’s problems with tetrahedral, Cartesian, and PEBI-grids. Finally, the paper presents a fully-coupled 3D simulation with multiple inclined intersecting faults activated in shear by fluid injection, which caused an increase in effective reservoir permeability. Our approach allows for great reduction in the complexity of the (gridded) model construction while retaining the solution accuracy together with great saving in the computational cost compared with UDFM. The flexibility of our model with respect to the types of grid polyhedra allows us to eliminate mesh artifacts in the solution of the transport equations typically observed when using tetrahedral grids and two-point flux approximation.

A Novel Naturally Fractured Reservoirs Classification Plot Through the Liaison of Dynamic Data, Depositional Environments and Rock Texture

Naturally Fractured Reservoirs (NFR) represent a challenge for petroleum industry because they are characterized by complex dynamics associated to the fluids motion and geological events that originated them million years ago, where diagenetic processes have played a transcendental role. In carbonates, the movement of fluids within the reservoir is highly influenced by the fracture systems present in the formation, however, these are intimately related to rock texture and quality, depositional environments, facies changes, regional and local stresses, tectonism and of course, diagenesis. Regarding the dynamic behavior, we can highlight the importance of the type of fluid present in the system and the acting drive indices, which govern the behavior of pressure and production in this type of reservoirs, whose analysis usually goes further of conventional techniques commonly used for its evaluation. One of the problems faced by reservoir engineers is the classification or categorization of these types of reservoirs to know their true potential and try to estimate the recoverable reserves as accurately as possible, since the complex dynamic behavior of NFR hinders its exploitation when the most important parameters for its correct evaluation are not known. From the above, a novel and practical Naturally Fractured Reservoirs (NFR) classification plot is proposed based on the Nelson's classification (2001) and a full revision of other author's technical reviews. The plot is generated through the information obtained from a full reservoir characterization to acquire petrophysical evaluations and Pressure Transient Analysis (PTA) to find the product of the effective porosity and the average flow capacity of each of the fields tested in order to plot them against the recovery factor; this analysis considered more than 200 carbonate fields from more than 40 countries around the world. When plotting the data involved, it is clear to see that they are grouped in different zones for its reclassification as Naturally Fractured Reservoirs, where we added a subcategorization of type II reservoirs (type II A and type II B) and also the influence of vugs in type I reservoirs and the gas and condensates region; all attributed to the dynamic behavior associated to the type of fluid, the acting drive indices, the depositional environments and the rock texture. The results obtained were fully coupled to a probability distribution and have shown to be consistent with the observed behavior, being a useful tool for determining the actual type of NFR, the expected production rates, the range of possible recovery factors to be achieved and the characterization of reservoirs. Likewise, the proposed plot can be applied to the analysis of sectors in the same reservoir or formation to try to identify the variations regarding the type of NFR by zones, blocks or compartments according to the location of each well in the field, considering their respective recovery factors concerning its cumulative production and original reserves.

Numerical Investigation of Wettability Effects on Two-Phase Flow in Naturally Fractured Reservoirs Using Complex System Modelling Platform

Wettability is an essential component of reservoir characterization and plays a crucial role in understanding the dominant mechanisms in enhancing recovery from oil reservoirs. Wettability affects oil recovery by changing (drainage and imbibition) capillary pressure and relative permeability curves. This paper aims to investigate the role of wettability in matrix-fracture fluid transfer and oil recovery in naturally fractured reservoirs. Two experimental micromodels and one geological outcrop model were selected for this study. Three relative permeability and capillary pressure curves were assigned to study the role of matrix wettability. Linear relative permeability curves were given to the fractures. A complex system modelling platform (CSMP++) has been used to simulate water and polymer flooding in different wettability conditions. Comparing the micromodel data, CSMP++ and Eclipse validated and verified CSMP++. Based on the results, the effect of wettability alteration during water flooding is stronger than in polymer flooding. In addition, higher matrix-to-fracture permeability ratio makes wettability alteration more effective. The results of this study revealed that although an increase in flow rate decreases oil recovery in water-wet medium, it is independent of flow rate in the oil-wet system. Visualized data indicated that displacement mechanisms are different in oil-wet, mixed-wet and water-wet media. Earlier fracture breakthrough, later matrix breakthrough and generation and swelling of displacing phase at locations with high horizontal permeability contrast are the most important features of enhanced oil recovery in naturally fractured oil-wet rocks.