Reservoir Engineering Data Research Articles

Mechanisms of Waterflood Inefficiency: Analysis of Geological, Petrophysical and Reservoir History, a Field Case Study of FWU (East Section)

The petroleum reservoir represents a complex heterogeneous system that requires thorough characterization prior to the implementation of any incremental recovery technique. One of the most commonly utilized and successful secondary recovery techniques is waterflooding. However, a lack of sufficient investigation into the inherent behavior and characteristics of the reservoir formation in situ can result in failure or suboptimal performance of waterflood operations. Therefore, a comprehensive understanding of the geological history, static and dynamic reservoir characteristics, and petrophysical data is essential for analyzing the mechanisms and causes of waterflood inefficiency and failure. In this study, waterflood inefficiency was observed in the Morrow B reservoir located in the Farnsworth Unit, situated in the northwestern shelf of the Anadarko Basin, Texas. To assess the potential mechanisms behind the inefficiency of waterflooding in the east half, geological, petrophysical, and reservoir engineering data, along with historical information, were integrated, reviewed, and analyzed. The integration and analysis of these datasets revealed that several factors contributed to the waterflood inefficiency. Firstly, the presence of abundant dispersed authigenic clays within the reservoir, worsened by low reservoir quality and high heterogeneity, led to unfavorable conditions for waterflood operations. The use of freshwater for flooding exacerbated the adverse effects of sensitive and migratory clays, further hampering the effectiveness of the waterflood. In addition to these factors, several reservoir engineering issues played a significant role in the inefficiency of waterflooding. These issues included inadequate perforation strategies due to the absence of detailed hydraulic flow units (HFUs) and rock typing, random placement of injectors, and uncontrolled injected fresh water. These external controlling parameters further contributed to the overall inefficiencies observed during waterflood operations in the east half of the reservoir. A detailed understanding of the mechanistic factors of inefficient waterflood operation will provide adequate insights into the development of the improved recovery technique for the field.

Investigation on the Extent of Retrograde Condensation of Qianshao Gas Condensate Reservoir Using PVT Experiments and Compositional Reservoir Simulation

In the development of the Qianshao (QS) gas condensate reservoir, it is crucial to consider the phenomenon of retrograde condensation. Understanding the condensate saturation distribution with respect to time and space within the reservoir is essential for planning and implementing effective strategies for the future development of the QS gas condensate reservoir. In this paper, various PVT experiments (including reservoir oil recombination, flash separation, constant composition expansion, and constant volume depletion) were conducted to study the PVT properties and phase behavior of QS gas condensate fluid. Based on experimental data, our in-house PVT computation package was used to determine the appropriate EOS model parameters for the QS gas condensate. A four-step reservoir fluid characterization procedure and workflow for gas condensate reservoirs was developed. Furthermore, by analyzing the pressure-temperature phase envelope, the maximum possible condensate saturation in the QS well area was estimated to be around 3%. Numerical reservoir simulation models were developed using both the EOS model and actual reservoir engineering data. These simulation models were specifically designed to replicate the retrograde condensation process that occurs during production, taking into account both vertical and horizontal wells. By simulating the production process, these single-well reservoir simulation models enable us to quantitatively evaluate the condensate saturation and its distribution over space and time within a specific control area around a single well. Reservoir simulation results show that the condensate build-up around vertical and horizontal wells is quite different. For a vertical well, the maximum condensate oil saturation (30%) around the wellbore is located approximately 5 to 6 m from the well’s center. In contrast, the horizontal well model demonstrates a maximum condensate saturation of no more than 1.5%. This information is crucial for making informed decisions regarding the effective development and management of the QS gas condensate reservoir.

Floodwater utilization potential assessment of China based on improved conceptual model and multi-reservoir basin assessment method

Floodwater resource utilization is an important way to alleviate the water resources shortage in China. The quantitative assessment of the floodwater utilization potential under the current engineering conditions is vital for implementation of floodwater resource utilization. However, the imperfect conceptual model of floodwater utilization potential, the limited availability of reservoir engineering data, and the lack of universal assessment method that directly considers the reservoirs regulation capacity pose a major challenge to assessment of floodwater utilization potential in China. This study improves the universality of the previous conceptual model of floodwater utilization potential by analyzing the differences and connections of floodwater resources potentials under different states of utilization. The floodwater utilization potential assessment method for river basin with multi-reservoir was also proposed based on our previous assessment method for single reservoir controlled basin. The assessment method was used to evaluate the floodwater utilization potential of the first- and second-level water resources regions in China based on the reanalyzed monthly runoff data (1902 ∼ 2014) and large and medium-sized reservoirs data (as of 2015). Results indicate that the annual average total floodwater utilization potential of China was calculated as 668.62 billion m3 under the current reservoir regulation capacity, accounting for 34.05% of the total floodwater water resources in China. The study demonstrated that the frequency curve of floodwater utilization potential can provide a better understanding of the states of floodwater utilization, and the assessment method. Strategies for long-term floodwater utilization and flood control planning in different regions of China were also provided to government in our study.

Geomechanics Successfully Implemented in a Deepwater Setting

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202146, “Successful Implementation of Geomechanics in a Deepwater Setting: A Case Study From KG Offshore India,” by Sarah Bhimpalli, ONGC; Ashok Shinde, Baker Hughes; and Bayye L. Rao, ONGC; et al. The paper has not been peer reviewed. _ Geomechanics plays an important role in assessing formation integrity during well construction and completion. In the complete paper, study field K belongs to a Plio-Pleistocene sequence in a deepwater environment with hydrocarbon prospects. As a part of exploration activity, four existing offset oil wells were considered for geomechanical model construction. The geomechanical model for the field was built by integrating available drilling, geology, petrophysics, and reservoir data. The methodology adopted in this paper highlights how a reliable geomechanical model can be built for a field with data constraints. Introduction The present study block is in deep water off the eastern Indian coast in the KG basin, with several hydrocarbon discoveries in a clay formation. These reservoirs have been deposited under marine conditions, and source rock is thought to be Eocene to Oligocene marine shale. During drilling, as the rock on the wellbore track was drilled and brought out of the hole, the drilling fluid would exert a corresponding pressure on the wellbore wall and the stress of the rock surrounding the wellbore would be redistributed, generating induced stress. To maintain wellbore stability, use of a drilling fluid of appropriate density (mud weight) to control induced wellbore stress is essential. Shear and tensile failures are the major causes of mechanical instability in boreholes. If it rises past the appropriate upper limit, drilling-fluid pressure can cause tensile failure in the wellbore wall; if lower than the appropriate lower limit, drilling-fluid pressure can cause shear failure in the wellbore wall. Because of several drilling complications and nonproductive time experienced during the exploratory phase, building of a geomechanical model for safe and cost-effective drilling during the development phase is necessary. The existing four wells (W, X, Y, and Z) targeted the hydrocarbon play. Using the data from the four offset wells, a comprehensive geomechanical study was completed. The main objectives of the study included pore-pressure prediction, wellbore-stability analysis, well-trajectory optimization, and sanding prediction. 1D Geomechanical Modeling To analyze wellbore stability, well logs, laboratory test results, and drilling reports of the wellbore were used to determine geomechanical characteristics of the drilled formations. The elastic properties, rock strength characteristics, in-situ stresses, and pore pressures are the most important geomechanical characteristics to be measured or calculated. The geomechanical model was built by integrating drilling, geology, petrophysics, and reservoir engineering data. The work flow to build the geomechanical model is presented in Fig. 2 of the complete paper. Vertical stress (Sv) was estimated by integration of density logs from seabed to reservoir. Pore pressure was predicted using normal compaction trend (NCT) on log data. Minimum horizontal stress (Shmin) was constrained using leakoff tests (LOTs) and mini- and microfracturing data. No rock-mechanical testing data were available, and rock properties were estimated from petrophysical logs using regional experience. Magnitude and orientation of maximum horizontal stress (Shmax) was constrained using the presence of stress-induced wellbore failures on image and caliper logs.

A Comprehensive Review of Fracture Characterization and Its Impact on Oil Production in Naturally Fractured Reservoirs

Naturally fractured reservoirs are indescribable systems to characterize and difficult to produce and forecast. For the development of such reservoirs, the role of naturally forming fractures in the different development stages needs to be recognized, especially for the pressure maintenance and enhanced oil recovery stages. Recent development in the field of naturally carbonate fractured aimed at fracture characterization, fracture modeling, and fracture network impact of fracture networks on oil recovery were reviewed. Consequently, fracture identification and characterization played pivotal roles in understanding production mechanisms by integrating multiple geosciences sources and reservoir engineering data. In addition, a realistic fracture modeling approach, such as a hybrid, can provide a more accurate representation of the behavior of the fracture and, hence, a more realistic reservoir model for reservoir production and management. In this respect, the influence of different fracture types present in the reservoir, such as major, medium, minor, and hairline fractures networks, and their orientations were found to have different rules and impacts on oil production in the primary, secondary, and EOR stages. In addition, any simplification or homogenization of the fracture types might end in over or underestimating the oil recovery. Improved fracture network modeling requires numerous considerations, such as data collection, facture characterization, reservoir simulation, model calibration, and model updating based on newly acquired field data are essential for improved fracture network description. Hence, integrating multiple techniques and data sources is recommended for obtaining a reliable reservoir model for optimizing the primary and enhanced oil recovery methods.

Toolkit Approach Aids Design of CCS Projects in Depleted Offshore Fields

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 31651, “A Toolkit for Carbon Capture and Storage in an Offshore Depleted Gas Field,” by Raj Deo Tewari, SPE, Chee Phuat Tan, SPE, and Mohd Faizal Sedaralit, SPE, Petronas. The paper has not been peer reviewed. Copyright 2022 Offshore Technology Conference. Reproduced by permission. Comprehensive screening for site selection has been carried out for suitable carbon dioxide (CO2) storage sites offshore Sarawak, Malaysia, using geographical, geological, geophysical, geomechanical, and reservoir engineering data and techniques for evaluating storage volume, container architecture, pressure, and temperature conditions. The site-specific input data are integrated into static and dynamic models for characterization and generation of performance scenarios of the site. Three-way coupled modeling helped to understand the likely state of injectants in the future and associated storage mechanisms. The work flow described in the complete paper may be adopted to evaluate other CO2 projects in both carbonate and clastic reservoirs for long-term storage of greenhouse gas (GHG) worldwide. Introduction Because fossil fuels are expected to remain a significant energy source until at least the middle of this century, techniques to capture and store produced CO2, combined with other efforts, could help stabilize GHG concentration in the atmosphere. The toolkit the authors present in the complete paper can help to design carbon capture and storage (CCS) projects for the oil and gas industry offshore. The authors aim to meet the following goals: - Provide process descriptions by which CCS can protect the environment - Describe steps required in planning and execution and post-operation - Protect human health and safety - Protect underground sources of drinking water and other natural resources - Comply with regulations for emissions reduction - Deploy technologies in an efficient and cost-effective manner The authors devote much of the complete paper to a discussion of factors to be considered in storage-site screening and selection, including the characteristics of different types of storage sites and their mechanisms once CO2 is injected.

OPTIMIZATION STUDY OF GATE OPERATION RULE IN CIAWI DAM AS FLOOD CONTROL FUNCTION

The purpose of this research is to find out the effectiveness of operating gate on the design of flood routing and provide an alternative outlet operation gate for maximum flood reduction. The location of the research area is the Ciawi Dam watershed with an area of ​​88.50 km2, a river length of ±16.70 km and an average river slope of 5.60%. This research data is based on climatological data, low discharge data, flood hydrograph, and dam and reservoir engineering data. In addition, there are supporting data to perform calculations and analyzes, such as flood discharge data, elevation curve – reservoir volume and layout of the dam and its complementary buildings, existing operating patterns, and regional socio-economic data studies. The method used is to calculate flood routing of the capital flow curve at the outlet operation gate. The simulation is carried out using a design flood hydrograph so that optimal flood reduction can be determined by the outlet operation gate. Based on the results of the maximum reduction in the design of the reservoir operation dam design without utilizing the conduit gate as a flood control function, the researchers optimized the door operation pattern to increase the flood reduction capacity (optimization) of the Ciawi Dam. The result of the calculation and analysis is that the flood return period (Q25 th) is able to reduce flooding by 54.64%; flood return period (Q50 yr.) is able to reduce flooding by 45.21%; flood return period (Q100 yr.) is able to reduce flooding by 38.06%; flood return period (Q500 yr.) is able to reduce flooding by 38.50%; and the flood return period (Q1000 yr.) was able to reduce flooding by 33.22%. So, it can be concluded that by utilizing the bottom outlet gate as a flood discharge regulation, the benefits obtained are 42.27% (at Q 25 yrs.) from the pattern of dam operation without gate regulation.

Fast evaluation of pressure and saturation predictions with a deep learning surrogate flow model

Numerical models for flow through porous media are essential for forecasting subsurface fluid flow response to support optimal decision-making to develop subsurface resources such as groundwater, geothermal, and oil and gas. For reservoir engineering, numerical flow simulation modeling is applied to support and maximize well ultimate recovery and recoverable reserves to maximize project economics and safety while minimizing environmental impacts. Subsurface models explore subsurface uncertainty based on integrating geological, geophysical, petrophysical, and reservoir engineering data and expert interpretations.To evaluate uncertainty, we rely on multiple geostatistical subsurface heterogeneity realizations paired with flow simulation forecasts to test the sensitivity of various reservoir development parameters and build an uncertainty model of reservoir performance. However, with large reservoir models, numerical flow simulation time increases, leading to a significant amount of professional time and computational effort that increases project costs, and increases cycle times resulting in delay or diminished decision quality. This issue motivates the utilization of surrogate, computationally efficient approximative flow models. Current methods focus on prediction accuracy and minimizing prediction error. When uncertainty is significant, prediction accuracy is insufficient, and we must consider the entire uncertainty distribution.We propose a new and general workflow to generate accurate and precise machine learning-based surrogate flow models to predict the relationship between the reservoir rock and fluids, development parameters, and the reservoir flow simulation responses. We train a deep convolutional neural network using the results from a three-dimensional two-phase flow simulator. Next, we use the trained model to generate ensemble predictions from the flow surrogate to evaluate the uncertainty based on the development parameters and geological information.The machine learning-based surrogate model uses exhaustive subsurface predictor features, porosity, permeability, well position, and an engineered feature representing non-dimensional time as input to predict exhaustive subsurface response features, pressure, and saturation distribution over discrete time steps as the output. The proposed workflow integrates the spatiotemporal aspect of subsurface flow modeling. It allows the practitioner engineer to explore subsurface uncertainty without the entire computational cost of numerical flow simulation to support optimum, timely development decision-making.

Implementation of an Integrated Geochemical Approach Using Polar and Nonpolar Components of Crude Oil for Reservoir-Continuity Assessment: Verification with Reservoir-Engineering Evidences

Summary The ability of geochemistry techniques in reservoir-continuity studies has already been proved. Most of the traditional methods mainly involve analyzing nonpolar components of crude oil and overlooking polar components. Despite valuable information obtained from nonpolar components, these compounds are sometimes affected by various alterations or likely provide only a piece of the reservoir-compartmentalization puzzle. In this paper, an integrated geochemical approach that uses nonpolar (i.e., saturates and aromatics) and polar (i.e., asphaltenes) components of crude oil was performed to evaluate reservoir continuity efficiently. The Shadegan Oil Field in the Dezful Embayment in southwest Iran was investigated for reservoir-continuity studies to show the efficiency of this proposed technique. The selected interparaffin peak ratios and light hydrocarbons [the C7 oil correlation star diagram (C7CSD)] from whole-oil gas chromatography (GC) (WOGC) chromatograms were used to obtain oil fingerprints from the nonpolar fraction of crude oils. The Fourier-transform infrared (FTIR) spectroscopy of asphaltenes was applied to obtain oil fingerprints from the polar fraction of crude oils. The pairwise comparison of studied wells by each technique was summarized in a similarity matrix with green, yellow, and red colors to show connectivity, limited connectivity, and disconnectivity according to oil fingerprints. Finally, a compartmentalization model was prepared from the integrated results of different techniques considering the worst-case scenarios regarding the occurrence or absence of reservoir continuity when relying on individual methods for the studied field. Results show that the Shadegan Oil Field comprises three zones in the Asmari Reservoir and two zones in the Bangestan Reservoir. Reservoir-engineering data, including pressure data and pressure/volume/temperature (PVT), completely corroborated the obtained results from the geochemical approach. The consistency of results suggested FTIR oil fingerprinting of asphaltene as a novel and straightforward technique, which is a complementary or even alternative method with respect to previous geochemical methods.

Implementation of Rock Typing on Waterflooding Process During Secondary Recovery in Oil Reservoirs: A Case Study, El Morgan Oil Field, Gulf of Suez, Egypt

Waterflooding is one of the most common secondary recovery methods in the oil and gas industry. Globally, this process sometimes suffers a technical failure and inefficiency. Therefore, a better understanding of geology, reservoir characteristics, rock typing and discrimination, hydraulic flow units, and production data is essential to analyze reasons and mechanisms of water injection failure in the injection wells. Water injection failure was reported in the Middle Miocene Hammam Faraun reservoir at El Morgan oil field in the Gulf of Suez, where two wells have been selected as injector’s wells. In the first well (A1), the efficiency of injection was not good, whereas in the other analog A2 well good efficiency was assigned. Therefore, it is required to assess the injection loss in the low efficiency well, where all aspects of the geological, reservoir and production data of the studied wells were integrated to get a complete vision for the reasons of injection failure. The available data include core analysis data (vertical and horizontal permeabilities, helium porosity, bulk density, and water and oil saturations), petrographical studies injection and reservoir water chemistry, reservoir geology, production, and injection history. The quality of the data was examined and a set of reliable X–Y plots between the available data were introduced and the reservoir quality in both wells was estimated using reservoir quality index, normalized porosity index, and flow zone indicator. Integration and processing of the core and reservoir engineering data indicate that heterogeneity of the studied sequence was the main reason for the waterflooding inefficiency at the El Morgan A1 well. The best reservoir quality was assigned to the topmost part of the reservoir, which caused disturbance of the flow regime of reservoir fluids. Therefore, it is clearly indicated that rock typing and inadequate injection perforation strategy that has not been aligned with accurate hydraulic flow units are the key control parameters in the waterflooding efficiency.

Giant and major-size oil and gas fields worldwide in basement reservoirs: state-of-the-art and future prospects

Oil and gas occurs in basement reservoirs in many parts of the world. The reserves of basement fields are as small as one or two million barrels of oil or gas-equivalent such as the Beruk Northeast pool in Sumatra, Indonesia to over 1.0 billion barrels of oil as in Viet Nam’s Bach Ho field and Libya’s Augila-Naafora field. This paper focuses on three giant-size oil and gas fields and six major-size fields. Exploration for oil and gas in basement has been remarkably successful in the past decade with important discoveries in basement in Indonesia, United Kingdom, Norway, Chad, and Argentina. In order to successfully develop basement oil and gas fields and also to avoid costly mistakes, all available geological, geophysical, reservoir engineering and economic data must be closely studied. Also, it is very important to study analogues worldwide of basement oil and gas fields in order to understand why some fields are very successful and others turn out to be technical and economic failures.

Hydrocarbon Vertical Continuity Evaluation in the Cretaceous Reservoirs of Azadegan Oilfield, Southwest of Iran: Implications for Reservoir Geochemistry

AbstractA collection of data obtained from analytical methods in geochemistry along with the reservoir engineering and geologic data were used to investigate the reservoir continuity in the Cretaceous Fahliyan, Gadavan, Kazhdumi and Sarvak reservoirs of the super‐giant Azadegan oilfield, SW Iran. The geochemical data indicate that the oil samples, with medium to high level of thermal maturity, have been generated from the anoxic marine marl/carbonate source rock(s). The Sargelu (Jurassic) and Garau (Cretaceous) formations are introduced as the main source rocks for the studied oils. The dendrogram obtained from the cluster analysis of high‐resolution gas chromatography data introduces two main oil groups including Fahliyan reservoir, and Kazhdumi along with Sarvak/Gadvan reservoirs. This is confirmed by C7 Halpern star diagram, indicating that, the light oil fraction from Fahliyan reservoir is distinct from the others. Also, different pressure gradient of the Fahliyan Formation (over‐pressured) relative to other reservoirs (normally‐pressured) show the presence of compartments. The relation between toluene/n‐heptane and n‐heptane/methylcyclohexane represents the compartmentalization due to maturation/evaporative fractionation for Fahliyan and water washing for other studied reservoirs. Also, the impermeable upper part of the Fahliyan Formation and thin interbedded shaly layers in the Kazhdumi, Sarvak and Gadvan formations have controlled reservoir compartmentalization.

A continuous learning algorithm for history matching

History matching is a classical petroleum reservoir engineering data assimilation process whereby a reservoir model is calibrated to reproduce the behavior of a real reservoir yielding more reliable models for reservoir management, reservoir performance forecast and field development decisions. In this paper, we introduce a continuous learning-from-data algorithm for history-matching problems that generates solutions using the patterns of input attributes identified in the k-best solutions for each variable involved in the process. The proposed algorithm consists of a two-staged optimization strategy, in which each stage handles different types of reservoir uncertain attributes. The proposed learning approach continuously evaluates the data of all-available models and supports the strategic choice of input patterns that can be used in the generation of different and eventually better history-matched models. We apply the proposed algorithm to the UNISIM-I-H benchmark case, a complex synthetic reservoir model based on Namorado field, Campos basin, Brazil. The results outperform the ones from related work for the same benchmark, indicating the efficiency and effectiveness of the proposed strategy towards improving the history-matching quality of an initial set of solutions, with a lower simulation footprint.

Eagle Ford and Pimienta Shales in Mexico: A Case Study

Summary Our objective in this paper is to highlight the potential of the Eagle Ford (Cretaceous) and Pimienta (Upper Jurassic) shales in Burgos Basin (Mexico) through a comparison with the Eagle Ford Shale in Texas. The comparison is a case study focused on real data and their interpretation, north and south of the border, including geochemistry, geology, production, and reservoir–engineering data. Our overall approach includes the description of Eagle Ford data in Texas, as well as Eagle Ford and Pimienta data in the Burgos Basin. The geologic comparison is carried out using cross sections of the various formations and geophysical data. Geochemical and petrophysical data are compared using specialized crossplots. Production data are compared through rate transient analysis and by investigating the different flow periods observed in wells in both sides of the border. Reservoir–engineering aspects are compared using material–balance methods developed specifically for analyzing multipurpose shale petroleum reservoirs. Results indicate that there are many similarities but also some differences between the Eagle Ford Shale in Texas and shales in Mexico. The geologic and seismic cross sections show that there is continuity of the Eagle Ford on both sides of the border. However, structural geology in Mexico tends to be more complex than that in Texas. The geological and geochemical descriptions also show important similarities in the rock mineralogy, and the quantity, quality, and maturity of the organic matter. Well–log data show the same pattern of distribution on modified Pickett plots, developed originally for evaluation of the Eagle Ford Shale in Texas. Production data in the Burgos Basin shales are characterized by long periods (several months or even years) of transient linear flow, something that compares well with the Eagle Ford in Texas. Specialized material–balance calculations, which consider multiple porosities, have been used in the Eagle Ford Shale in Texas and are shown to have similar application in the Burgos Eagle Ford and Pimienta shales. On the basis of the Eagle Ford Shale performance in Texas, and the similarities with Burgos shales, the conclusion is reached that there is significant potential in the Mexican Eagle Ford and Pimienta shales. We present a comparison of the interpretation of real geoscience and engineering shale data collected on both sides of the border. The comparison is meaningful and suggests that the potential of shale reservoirs south of the border will be quite significant. Mexico should benefit from the lessons learned from the Texas Eagle Ford Shale.

The effect of heterogeneity on NMR derived capillary pressure curves, case study of Dariyan tight carbonate reservoir in the central Persian Gulf

The porous network controls the behavior of fluids in the reservoir rocks. In carbonate reservoirs fluid flow characteristics do not certainly follow initial sedimentary fabrics. Therefore in these reservoirs, the properties of the porous network should be used in determining the facies. In this study, using a combination of petrographic, reservoir petrophysical and reservoir engineering data, porous network in Aptian-Albian Dariyan carbonates have been studied in one of the central Persian Gulf fields. Accordingly, four pore facies were determined by capillary pressure curves from mercury injection and nuclear magnetic resonance data in four different types of lithology with different microfacies. Also, 13 different petrophysical parameters of these curves derived from both methods and compared with each other. A clear trend was observed in reducing the reservoir quality from pore facies 1 to pore facies 4. The performance of the capillary pressure curves obtained from mercury injection and nuclear magnetic resonance and their derived parameters in 4 facies and the effect of lithology on these curves have been investigated. Results showed that the porosity of the NMR is completely independent of lithology and complexity of the porous system, while the permeability-dependent parameters are largely influenced by both lithology and pore system structure. It was also shown that the NMR curves are a suitable tool for determining the pore facies and their petrophysical parameters in homogeneous tight carbonate lithology with a simple porous system.

Применение микросервисной архитектуры при решении задач визуализации данных добычи и разработки нефтегазовых месторождений на базе гетерогенных кластеров

Применение микросервисной архитектуры при решении задач визуализации данных добычи и разработки нефтегазовых месторождений на базе гетерогенных кластеров

Using simulation and production data to resolve ambiguity in interpreting 4D seismic inverted impedance in the Norne Field

The Norne Field started production in 1997 and up to 2006 the field experienced intense production activity, making the Norne benchmark case an ideal candidate to explore the challenges in interpreting complex time-lapse seismic data. Seismic amplitude changes and time-shifts are used as the first level approach to interpret the time-lapse differences and to update reservoir models. A common alternative is to invert the seismic data and obtain acoustic impedance variations caused by production activity, and to evaluate their possible interpretations. For this case study, we use a 4D inversion approach to invert the base (2001) and monitor (2006) seismic surveys in order to provide field-wide insights for the Norne benchmark case. We extensively interpret the observed 4D inversion anomalies and decouple, as much as possible, the effects of fluid and pressure variations, supported by production and reservoir engineering data. Moreover, we compare the inversion results with the simulation model from the Norne benchmark case to suggest areas of future modification to the simulation model. This research is intended as a resource to improve the quality of history matching or other 4D inversion methods applied to the Norne benchmark case, and to demonstrate a detailed time-lapse seismic interpretation within the reservoir segments of the Norne Field. Supplementary material: Well-history data of six producer and injector wells is available at https://doi.org/10.6084/m9.figshare.c.3890251

A field-scale investigation of residual and dissolution trapping of CO2 in a saline formation in Western Australia

In a typical carbon capture and storage project, residual and dissolution trapping is expected to play a significant role in minimising the risk associated with the containment. Various methods of maximising each trapping mechanism individually have been proposed in the literature. Yet, in actual projects, it is expected that these trapping mechanisms occur interactively. This area still remains unexplored.This paper presents the results of a numerical investigation of technically feasible engineering designs to co-optimise both trapping mechanisms. It integrates a geological model developed for an actual saline formation in Australia, along with other available reservoir engineering data using a compositional numerical reservoir simulator. The scenario involves injecting supercritical CO2 at a commercial rate into a thick, deep, layered, heterogeneous, high porosity, high-permeability sandstone formation that initially contains only water of high salinity. The design objective is to inject more than 200 million tonnes of CO2 over 40 years. Compositional interactions between formation water and injected CO2 are modelled using the Peng–Robinson equation of state. We examine different injection schemes to find out the scenario that maximises dissolution and residual trapping. These schemes include vertical wells, horizontal wells, water alternate gas injection (WAG) and simultaneous water and gas injection (SWAG).The results show that heterogeneity has a significant effect on the location of perforations. The middle region of the Wonnerup Member appears to be the optimum location for CO2 injection where desired amount of CO2 can be injected while a maximum benefit of residual trapping can be achieved. Horizontal wells appear to enhance residual trapping the most, whereas WAG enhances dissolution trapping the most. Furthermore, WAG scenarios result in the least mobile CO2, and therefore, show the highest cumulative potential for both residual and dissolution trapping. However, in terms of relative economics, vertical injection wells appear to be the most viable option.

Enhancement of dynamic reservoir interpretation by correlating multiple 4D seismic monitors to well behavior

We have found that dynamic reservoir interpretation can be enhanced by directly correlating the seismic amplitudes from many repeated 4D seismic monitors to the field production and injection history from wells. This “well2seis” crosscorrelation was achieved by defining a linear relationship between the 4D seismic signals and changes in the cumulative fluid volumes at the wells. We also found that the distribution of the well2seis correlation attribute can reveal key reservoir connectivity features, such as the seal of faults, fluid pathways, and communication between neighboring compartments. It can therefore enhance dynamic reservoir description. Based on this enhanced interpretation, we have developed a workflow to close the loop between 4D seismic and reservoir engineering data. First, the reservoir model was directly updated using quantitative information extracted from multiple surveys, by positioning and placing known barriers or conduits to flow. After this process, a seismic-assisted history matching was applied using the well2seis attribute to honor data from the seismic and engineering domains, while remaining consistent with the fault interpretation. Compared to traditional history matching, that attempts to match individual seismic time-lapse amplitudes and production data, our approach used an attribute that condensed available data to effectively enhance the signal. In addition, the approach was observed to improve the history-matching efficiency as well as model predictability. The proposed methodology was applied to a North Sea-field, the production of which was controlled by fault compartmentalization. It successfully detected the communication pathways and sealing property of key faults that are known to be major factors in influencing reservoir development. After history matching, the desired loops were closed by efficiently updating the reservoir simulation model, and this was indicated by a 90% reduction in the misfit errors and 89% lowering of the corresponding uncertainty bounds.

Seismic data conditioning and neural network-based attribute selection for enhanced fault detection

In this study of the Dorood oil field, offshore Iran, 3D seismic data were utilized to identify a complex fault pattern in the highly faulted and fractured Fahliyan Formation. To enhance data quality and improve attribute accuracy and detection power, a steering cube was first computed based on a sliding 3D Fourier analysis technique, using the concept of directivity. The steering cube, which contains dip and azimuth information for each trace, was utilized for calculation of dip-steered filters and attributes. We applied the dip-steered median filter to remove random noise and to enhance laterally continuous seismic events by filtering along the structural dip. Several fault identification attributes, such as dip, curvature, coherency and similarity, and a meta-attribute of a ridge enhancement filter, were extracted from dip-steered, noise-attenuated data. A supervised, fully connected multi-layer perceptron neural network was constructed to select and combine the most sensitive fault attributes. The neural network, trained at identified fault and non-fault locations, was applied to the whole seismic volume to generate a cube of fault probability. Interpretations of major faults and fractures were integrated with geological, reservoir engineering and production data to highlight the role of these heterogeneities on dynamic reservoir properties. Faults and fractures in the Fahliyan reservoir were identified in general to have the effect of decreasing reservoir permeability. While most of the faults recognized have locally a sealing capacity effect, when the fault throws are large enough to bring into contact the Manifa and Yamama reservoirs, they act as a conduit for fluid communication and, wherever a well crosses a major fault, early water breakthrough is observable.