In -situ combustion (ISC) involves compression and injection of air into heavy/extraheavy oil reservoirs for enhancing production and recovery. Initially, ISC was very popular due to its high theoretical thermal efficiency, though more failures than successes in the 1990s made this process unpopular. It is a fact that it is now widely considered archaic. However, Suplacu de Barcau (Romania) and Balol-Santhal (India) ISC projects have brought the process back into focus. Performance of the Balol- Santhal-Bechraji over the last 25 years provides clarity to answer the question "Failure to enhance oil production and recovery by ISC: Myth or fact? " The author appreciates the views, decisions, and efforts of all global scientists/engineers/operators associated with the ISC process in the laboratory/field. Opinions and views presented in this paper are solely based on the author's experience, which may be in line or may differ. The discovery of heavy oil northwest of the Cambay Basin, India, in the 1970s led to the initiation of research and development in thermal processes. The depth, rock, and fluid characteristics, drive mechanism, and semi -arid area led to the testing of ISC over steam -flood in Balol. Laboratory findings are key to understanding the reaction kinetics of oil and process manifestations. Upgrading of oil is the key manifestation of ISC in the laboratory, but it is not seen in the field due to blending in long-distance displacement methodology. The involvement of laboratory personnel in design and surveillance plays an important role in the success of the project. Over the last 25 years, the Balol-Santhal ISC projects demonstrate the rejuvenation of declining fields with sustained enhanced oil production and an increase in recovery. Lessons of the Bechraji field indicate that process does not succeed in all reservoir settings. It is particularly suited to relatively clean, mobile heavy oil reservoirs with structural relief. Long-distance displacement of oil (vertical injector-vertical/horizontal producer spaced apart) is effective in a mobile oil reservoir. With low mobility oils, a short-distance oil displacement process using a pair of vertical injector and horizontal producer (horizontal well placed below the air injector) can be the preferred way for exploitation. This methodology has also the potential to capture upgraded oil. The process attracts more value when it is designed as operator friendly and flexible, integrating with gravity. Appropriate ignition types, continuous surveillance, maintaining optimum air injection rates, and re-engineering are important for the success of ISC. Success depends on the fabric and architecture of the reservoir, the way it is designed and implemented, and by integration of knowledge gained in the journey from laboratory to field with the process. It can be concluded that the perception of the ineffectiveness of ISC to enhance oil production and recovery from mobile heavy/extraheavy oil reservoirs cannot be generalized as a fact.
An underground stress state might be disturbed in an area, particularly adjusting to an active shear zone. Borehole breakouts (BOs) that appeared in a circular hole excavated in an inhomogeneous stress field might be tracked to identify the active shear zone. The present study aims to develop the breakout morphology analysis (BMA) algorithm to exploit the valuable attributes of borehole BOs including azimuth, width, and intensity (depth of elongation) of failure from wellbore ultrasonic imaging tools. In the current study, the extracted azimuthal information was surveyed to detect the active shear zone along the well. Ultrasonic data from five wells drilled in the doubly plunging Ahvaz Anticline located in Iran were collected for the purpose of algorithm verification. The multiwell correlation of the BOs' azimuth generated by the algorithm in the Ahvaz Anticline suggests a shear plan dipping southwest- northeast direction is possibly active in the deep vertical wells. Similarly, the seismic reflection profile of the Ahvaz Anticline shows a track of detachment faulting system in the mid- Cretaceous sediments. The finding confirms that the raw ultrasonic traveling time is more applicable than other borehole image data, such as static and dynamic images of ultrasonic amplitude, in BO characterization.
The significant quantities of oil contained in fractured karst reservoirs in Brazilian pre-salt fields adds new challenges to the development of upscaling procedures to reduce time on numerical simulations. This work aims to represent multiscale heterogeneities in reservoir simulators based on special connections between matrix, karst, and fracture mediums, both modeled in different grid domains within a single porosity flow model. The objective of this representation is a good balance between accuracy and simulation time. The principle combines the Embedded Discrete Karst Model (EDKM) and the Special Connection Fracture Model (SCFM), both developed by Correia et al, 2019. Therefore, this work extends the approach of special connections to integrate both karst and fracture mediums modeled in different grid domains and block scales. For a proper validation and numerical verification, we applied the methodology to a complex case study. The reference model is a refined grid model with: (1) an arrangement of large conduits (karsts), which are poorly connected, (2) a well-connected and orthogonal system of fractures and (3) a background medium (matrix). For the simulation model, the matrix grid domain has a grid block size of roughly 25 × 25 × 5 meters. The fracture domain has a grid block size of roughly 50 × 50 × 5 meters and the karst grid domain has the same block size as the reference model. Well-connected fractures are upscaled to the fracture domain by applying the Oda (1985) method. The results show a significant performance improvement regarding a dynamic matching response with the reference model, within a suitable simulation time and maintaining the dynamic resolution according to the representative elementary volume of heterogeneities, without using an unconstructed grid. Therefore, this work introduces a new method that can be applied to commercial flow simulators concerning the use of special connections to represent multiscale heterogeneities in flow simulators, without disregarding the accuracy over upscaling and an adequate simulation time.
Low primary and secondary recoveries of original oil in place from modern unconventional reservoirs begs for utilization of tertiary recovery techniques. Enhanced Oil Recovery (EOR) via cyclic gas injection ("huff ‘n puff") has indeed enhanced oil recovery in many fields and many of those projects have also been documented in industry technical papers/case studies. But the need remains to document new techniques in new reservoirs. This paper documents a small scale EOR pilot project in the eastern Eagle Ford and shows promising well results. In preparation for the pilot, full characterization of the oil and injection gas was done along with laboratory testing to identify the miscibility properties of the two fluids. Once the injection well facility design was completed a series of progressively larger gas volumes were injected followed by correspondingly longer production times. Fluids in the returning liquid and gas streams were monitored for compositional changes and the learnings from each cycle led to adjustments and facility changes to improve the next cycle. After completing five injection/withdrawal cycles in the pilot a few key observations can be made. The implementation of cyclic gas injection can be both a technical and a commercial success early in its life if reasonable cost controls are implemented and the scope is kept manageable. The process has proved to be both repeatable and predictable allowing for economic modeling to be utilized to help determine timing of subsequent injection cycles. A key component of the success of this pilot has been the availability of small compressors capable of the high pressures required for these projects and learning how to implement cost saving facility designs that still meet high safety standards.
Summary The emerging Paradox Oil Play in southeastern Utah is among the most significant unconventional plays in the western USA. The mean total undiscovered oil resources within just the Pennsylvanian Cane Creek interval of the Paradox Basin are believed to exceed 215 million barrels. However, to date, less than 5% (~9 million barrels) of the total Cane Creek resource has been produced from fewer than 40 wells, and only approximately one-half of those are horizontal wells. More than 95% of production is from the central Cane Creek Unit (CCU). Natural fractures are a key feature of many production wells, but stimulation by induced hydraulic fractures is not consistently successful. We hypothesize that more effective production in this play will rely on better fundamental characterization, especially on better quantification of the state of stress. Approximately 110 ft of core, well logs, and a diagnostic fracture injection test (DFIT) were acquired from the State 16-2 well within the CCU. With these data, we applied two methods to constrain and clarify the state of stress. The first technique, the Simpson’s coefficient method, provides lower bounds on the two horizontal principal stresses and relies on only limited data. Alternatively, the viscoelastic stress relaxation (VSR) method is used to estimate the least horizontal principal stress, building on observations that principal stresses become more isotropic as the viscous behavior of a rock is more pronounced. Results of these two methods support the hypothesis that the state of stress in the CCU of the Paradox Basin is nearly lithostatic and isotropic. Other factors consistent with this hypothesis include high formation pore pressure, which tends to reduce the possible stress states by changing the frictional failure equilibrium; lack of induced fractures in the core, which should be present in the case of stress anisotropy; and interbedded halite layers, which given their high degree of ductility, probably lead to greater VSR for the entire sedimentary package.
Polymer flooding is one of the most popular chemical enhanced oil recovery processes in the world, with many large -scale commercial field implementations. It improves mobility ratio and sweep efficiency over waterflooding. However, injection of high volumes of viscous fluid at high injection pressures almost inevitably induces fractures. Induced fractures are not necessarily negative for the flood, and they are documented to improve injectivity and reduce shear degradation of polymer. The big question is on their effect on areal and vertical sweep efficiency.Mangala is one of the largest and most commercially successful polymer floods in the world. The FM -1 unit has the highest stock tank oil initially in place among all the layers of Mangala. Polymer flood sweep efficiency in FM -1 is excellent despite the presence of injection-induced fractures and geological layering.Pressure falloff (PFO) studies are an important and inexpensive source of monitoring the growth of induced fractures in mature poly-mer floods. Extensive work has been done in the past to derive analytical solutions and numerically assisted solutions for polymer PFOs for non-Newtonian rheology and induced fractures with variable storage. There is also extensive and sometimes contradictory literature on polymer rheology in porous media at both high and low flux rates. Most of the work on polymer PFOs have published a few field examples or synthetic examples and addressed specific issues in depth.We have interpreted 40 PFOs carried out over a period of 1 year. All relevant data sources in the field on geomechanics, polymer rhe-ology in core and rheometers, temperature logs, and saturation logs were integrated to get a consistent estimate for fracture half-length. The results provide insight into the role of induced fractures in improving the sweep efficiency of FM -1. The arguments are backed with literature survey.The work can be used by operators around the world to manage mature polymer floods. The observations mentioned in the work can be used by researchers to fine tune their work. Secondary hypothesis on polymer rheology in porous media is also derived out of the work, which may be of academic interest and merit further work. There are other important aspects of polymer flood PFOs, such as impact of suspended solids and rock dilation near wellbore, which have not been explored in the paper.
Summary This paper develops a method for estimation of rock fabric number (RFN) from well logs in unconventional tight oil carbonates with permeability less than 0.1 md. The objective is to investigate the oil potential of a Middle Cretaceous tight carbonate in Mexico. The development of a method for these conditions is challenging as the current approach developed by Lucia (1983) has been explained for carbonates with permeability more than 0.1 md. Core data and drill cuttings available for this study are limited but provide important insights for the log interpretation and for identifying the presence of grainstone, packstone, and wackstone rocks in the unconventional tight carbonate under consideration. A crossplot of RFN vs. rp35 (pore throat radius at 35% cumulative pore volume) permits delimiting intervals with good production potential that are supported by well testing data. Information for the analysis of the Mexican carbonate comes from well logs of nine wells and two re-entry wells, four buildup tests, and a limited amount of core and drill cuttings information. All data were provided by a petroleum company and have been used, for transparency, without any modifications. An unconventional tight carbonate as defined in this paper has a permeability smaller than 0.1 md. The unconventional tight oil carbonate reservoir considered in this study includes 95% of data with permeabilities smaller than 0.1 md and only 5% with permeabilities larger than 0.1 md. The method introduced by Lucia (1983) and Jennings and Lucia (2003) for determining RFN is powerful, but they explained it only for permeabilities larger than 0.1 md, thus the need for a methodology that allows estimating from well logs the presence of grainstone, packstone, and/or wackstone in unconventional tight carbonate reservoirs with permeabilities smaller than 0.1 md. Results indicate that the RFN provides a useful approach for distinguishing grainstone, packstone, and wackstone rocks in unconventional tight carbonate reservoirs. Furthermore, rock fabric can be linked with Pickett plots to provide an integrated quantitative evaluation of RFN, porosity, water saturation, permeability, pore throat radius, and capillary pressure. This integration indicates that there is good oil potential in the Middle Cretaceous unconventional tight carbonate in Mexico.
Integrated reservoir-production modeling is a collaborative multidisciplinary tool that can facilitate optimization of oil and gas production operations during the field development planning stage of exploiting subsurface resources. The critical issue with this technique is the excessive computational burden of the large integrated model with many input variables, which has not been effectively addressed to date. This study aims to reduce the computational costs and runtimes associated with the production integration and optimization process from oil fields. To do so, the reservoir and the surface network models of an Iranian oil field were coupled to create an integrated model for the optimization of field parameters to achieve the highest oil production rate. In the first step of simplification, polynomial chaos expansion (PCE) was used to establish a surrogate model from the integrated system. Next, Sobol sensitivity analysis, which is a variance-based, global, and model -free sensitivity analysis technique, was performed to reduce the number of input variables by identifying the most influential variables. Finally, the optimization was implemented using genetic algorithm (GA) on the PCE surrogate model of the integrated system with the most important variables. The results from the case study showed that the integrated model can be replaced with the PCE surrogate model while the accuracy is maintained. Moreover, performing sensitivity analysis considerably decreased the number of input variables for optimization by revealing their significance. The proposed methodology in this study can substantially improve the computational efficiency of the optimization for the integrated reservoir-production system.
A significant amount of oil is contained in carbonate reservoirs, but only half of that oil can be produced by secondary enhanced oil recovery (EOR) methods. However, substantial improvements were made in EOR techniques and the prediction of carbonate reservoir performance within the last decades. Nevertheless, existing flow-simulation computer programs failed to provide a reliable prediction of such reservoirs due to their high heterogeneity and the reactivity of the rock. Potentially, in -situ combustion (ISC) is considered effective in developing heavy oils in carbonate reservoirs. The combustion reactions between crude oil and heterogeneous rock matrices introduce additional complexity to the simulation process. Also, most of the laboratory experiments studying the reaction kinetics of the ISC process are performed on the crushed core. However, to minimize the risks, improve the control of the process, and overcome upscaling issues, physical simulation must be carried out under conditions as close to the reservoir as possible. Consolidated core material in combustion tube (CT) experiments is desirable for better simulating some reservoir conditions with synthetic packs and for the cases when actual preserved reservoir core material may be available. Studying the relative effects of porosity and packing properties (specific surface area, sand grain distribution, and cementation) on the fuel is essential to evaluating the process under actual field conditions. This work presents a set of medium-pressure CT (MPCT) tests on crushed and consolidated cores and analyzes the differences, limita-tions, and performances of both approaches. Two MPCT tests were performed to evaluate the ISC feasibility on the heavy -oil carbonate reservoir with an initial oil saturation level of 0.38 to 0.50. According to previously published experimental results, such oil saturation levels can help avoid oil banking. Both experiments were conducted at reservoir conditions to consider the phase behavior at elevated pressures and temperatures. The method used in this research allows approbation of the methodology of ISC tests using consolidated core at high pressure, ensuring pack and process integrity during the experiment. The influence of consolidated core caused by significantly lower porosity and more uniform porous media elements than those made with unconsolidated material on combustion performance was assessed. Valuable data for different variations of combustion experiments were generated. This work compared two tests and presented the combustion parameters for a stabilized combustion period, such as fuel and air requirements, recovery efficiency, front velocity, and composition of produced gases. The research intends to demonstrate the potential application problems and address issues that might arise during ISC application on target reservoirs, including the higher air flux required for lower porosity of consolidated core samples. The experimental results performed under conditions closest to reservoir conditions are essential for further predictions and affect the ISC performance during pilot tests.
Summary Efficient reservoir models are more desirable for fast-paced reservoir management. Moreover, due to the complexity of flow underground, it is also essential to capture the fundamental physics for model reliability. Although they are fast, pure data-driven models frequently have issues associated with interpretability, physical consistency, and ability to forecast. On the other hand, we have used full-physics simulation models to mimic and investigate hydrocarbon systems for over several decades. However, considering its infrequent model updates related to high model complexity, it is a big challenge to manage reservoirs using full-physics models in short cycles. The objective here is to propose an approach that blends reservoir physics with data-driven models to fit in the framework of dynamic reservoir management. We propose to use a reservoir graph network (RGNet) modeling approach based on a diffusive time-of-flight (DTOF) concept to simulate reservoir behaviors. By assimilating field observation data (such as pressure and rates), an RGNet model can be used for future predictions, scenario studies, and well-control optimizations. By discretizing DTOF of a 3D system with multiple wells, RGNet simplifies the system into a graph network represented by a set of 1D grid blocks that significantly reduces the system complexity and run time. RGNet can also handle multiple flow problems with various types of physics. In this work, we propose to use two methods to develop reliable and parsimonious models scalable to large-scale systems. In addition, we propose a more robust method to assimilate pressure data. We applied the proposed approach to a synthetic and a field example. Two different history-matching algorithms, the ensemble smoother with multiple data assimilation (ES-MDA) and an adjoint-based method, are compared. While ES-MDA provides the capability for uncertainty analysis, an adjoint-based method generally requires fewer simulation runs to generate a posterior model. With the proposed methods for generating interwell connections, RGNet model calibration can be achieved without system redundancy and spurious long-distance well connectivity. Also, by using a more stable pressure-matching technique, we show that pressure data are better matched and reservoir volume is accurately characterized. RGNet provides a novel hybrid physics and data-driven reservoir modeling method to fit in closed-loop reservoir management (CLRM). As RGNet models are combined with fundamental flowing physics, the calibrated model parameters are easy to interpret and understand. An RGNet model runs with far less computational cost than required by a full-physics model, which allows it to be a more practical solution to history match, predict, and optimize real assets.
Summary This paper examines the buildup (BU) pressure response of a vertical well that penetrates an unconventional tight naturally fractured carbonate reservoir in Mexico. Four BUs in the same well over a period of 4 months, with intermediate flow periods, suggest partial closure of natural fractures. Radial flow is dominant in the four BUs. This is recognized in semilogarithmic and pressure derivative crossplots. However, the formulations require a consistent empirical component to match the BU data. The four BU tests are evaluated with a semi-empirical dual porosity model with restricted interporosity flow. The restricted flow between matrix and fractures is the result of partial secondary mineralization (cementation) within the fractures, which can be visualized as a natural positive skin that reduces the oil flow from the matrix to the fractures. The empirical part of the method is provided by a severity exponent (SE), which helps improve the match between the BU semilog and derivative plots. The BU evaluations permit estimating several parameters of interest, including fracture capacity (k2·h), skin, storativity ratio (ω), and the extrapolated pressure (p*). Results suggest that although natural fractures are present, they tend to close once the well goes on production. Thus, the conclusion is reached that the carbonate reservoir is tight and likely stress dependent. The calculated skin goes from an improved condition around the wellbore to slightly damaged conditions, probably due to fracture closure. The value of ω increases continuously, suggesting a tendency of the reservoir to move from dual to single porosity behavior. The reservoir is overpressured (0.87 psi/ft) and the extrapolated pressures (p*) decrease because of the tight characteristics of the reservoir. However, given the large size of the reservoir, the likelihood of depletion is low. The novelty of this study is the development of a new easy-to-use semi-empirical well testing model for matching the BU pressure response of four tests performed in a well that penetrates an overpressured, unconventional, tight, naturally fractured carbonate reservoir. The tests could not be matched with conventional methods currently available in the literature.
Summary A novel 2.5D intelligent gravity inversion technique has been developed to estimate basement topography. A deep neural network (DNN) is used to address the fundamental nonuniqueness and nonlinearity flaws of geophysical inversions. The training data set is simulated by adopting a new technique. Using parallel computing algorithms, thousands of forward models of the subsurface with their corresponding gravity anomalies are simulated in a few minutes. Each forward model randomly selects the values of its parameter from a set of predefined ranges based on the geological and structural characteristics of the target area. A DNN model is trained based on the simulated data set to conduct the nonlinear inverse mapping of gravity anomalies to basement topography in offshore Abu Dhabi, United Arab Emirates. The performance of the trained model is assessed by making predictions on noise-free and noise-contaminated gravity data. Eventually, the DNN inversion model is used to estimate the basement topography using pseudogravity anomalies. The results show the depth of the basement is between 7.4 km and 9.3 km over the Ghasha hydrocarbon reservoir. This paper is the 2.5D and improved version of the research (SPE-211800-MS) recently presented and published in the Abu Dhabi International Petroleum Exhibition & Conference (31 October–3 November 2022) proceedings.
The early Cretaceous formations in recent years are considered significant potential hydrocarbon- bearing rocks in many rift basins such as Komombo, south Egypt. Therefore, this study is focused on the critical analysis and interpretation of well logging together with seismic reflection data on the Al Baraka petroliferous reservoir in the Komombo subbasin. The interpretation of these data was used to construct the first 3D geophysical models in this area which were subsequently interpreted in terms of their potential to be hydrocarbon- bearing or not. The 3D petrophysical models were deduced to illustrate the spatial distribution and propagation of the petrophysical properties (laterally and vertically) within the reservoir. Additionally, 3D seismic models were prepared to get a comprehensive, in- depth picture of how the productive hydrocarbon reservoir zones are structurally controlled in different depths. So, these models are crucial for explaining reservoir characteristics and providing supported geological reservoir models for precise reservoir performance prediction. This study aims to differentiate and determine hydrocarbon potential zones in terms of the petroleum system. The results of these progressive analyses showed that only two zones (C and D) in the Six Hills Formation are considered the most productive zones because they have a large thickness of sand bodies, low- water saturation values, high porosity, and high permeability. These zones are located in the northeastern and central parts of the studied area, which represent the depocenter of the subbasin. This evidence supported and confirmed the presence of petroleum accumulations in certain zones within the Six Hills Formation. Therefore, this work can give and encourage experts with adequate knowledge to understand the development of the rift basins in Komombo and other basins in middle and south Egypt.
Summary This paper incorporates the findings of our previous publication (Morales and Lee 2022) and identifies, isolates, and quantifies elements in the annually disclosed proved reserves revisions that should not be considered technical or economic revisions. This has resulted in significantly different technical and economic revisions compared to those simplistically and directly derived using a common interpretation of the Financial Accounting Standards Board (FASB) Topic 932-235-50-5 (a) definition. We have assessed the reliability and comparability of the updated technical revisions when used to judge the reasonable certainty of the underlying proved reserves. We have carried out the analysis separating the proved reserves into developed and undeveloped. To derive a realistic data set to generate the updated technical and economic revisions, we reviewed more than 1,000 annual reports (10K and 20F Forms) and more than 600 comment letters from 141 companies filing annual reports to the Securities and Exchange Commission (SEC) during the period 2010–2020, extracting the information related to annual reserves changes and explicitly focusing on the disclosed revisions of previous estimates (RPE). We present evidence showing that the approach followed is robust and more reliable than the simple approach where technical revisions are estimated by simply subtracting the disclosed revisions due to price effects from the disclosed revisions in annual reports. The root causes for the significant differences between the simplistic approach and the one presented in this paper are mainly due to (1) including annual reserves changes due to nontechnical or economic factors as technical revisions, (2) using different interpretations of SEC and FASB regulations, and (3) not providing critical disaggregation information needed to estimate technical, economic, or other types of revisions correctly. Without proper consideration of these issues, the derived technical and economic revisions from disclosed data can be significantly distorted, affecting any conclusions derived. The annual average changes in technical revisions during a representative period, if correctly estimated, can provide an indication of both overstated and understated certainty of proved reserves estimates, which can impact a company’s relative valuation, asset impairment, internal depreciation, profit/loss, standardized measure, unit development costs, and other indicators based on proved reserves, making the reliability of the technical revisions and their actual upward or downward movements of paramount importance. We also highlight the significant different root causes driving the major differences between developed and undeveloped reserves in their annual technical revisions. The results indicate that for some companies that provide most of the information required for proper analysis, the certainty level of their disclosed developed and undeveloped proved reserves points toward an apparent overestimation of historically disclosed proved reserves. Our analysis shows the dubious quality and lack of reliability and comparability of the disclosed proved reserves revisions and highlights the limited value of existing guidance and current practices. We provide evidence that calls for FASB and SEC to provide complementary guidance in critical areas that currently limit the value, reliability, and comparability of the proved reserves revisions disclosed.
In recent years, time -lapse (4D) seismic (4DS) data have been widely used for reservoir monitoring to provide relevant information on dynamic changes occurring during production. In complex reservoirs, multiple seismic monitor surveys are usually available. Updating reservoir models with these data can be very beneficial to improve the field's management. In the quantitative integration of 4DS data into the data assimilation (DA) process, it is crucial to define how to deal with more than one seismic monitor. In this work, we continue a series of investigations about seismic DA procedures and expand on them by analyzing ways to assimilate more than one seismic monitor. More specifically, we evaluate different ways of using production data and two monitor surveys (M3 and M5) to calibrate the dynamic models of a real Brazilian reservoir using the ensemble smoother with multiple data assimilation (ES- MDA) method. We performed the following experiments: (1) sequential assimilation of M3 and M5 with parts of well history divided according to the seismic acquisition dates; (2) assimilation of M3 with the entire well history and subsequent assimilation of M5; (3) assimilation of well and M3 data; and (4) assimilation of well and M5 data. For comparison purposes, we also assimilated only well data. From the results, we observed that well and 4DS data misfits were reduced when assimilating both monitors, compared to the cases where only a single monitor (any of them) was used with production data. This conclusion is also true in the comparison with results obtained when only assimilating well data. This indicates that both seismic monitors are important data to be quantitatively considered in DA. In this particular field, using a previous DA run to solely assimilate the newly available monitor (Case 2) delivered better models and long -term forecasts. Therefore, this would be our recommendation. This study highlights the importance of several 4DS acquisitions for reservoir monitoring and management and shows the challenges of their application in seismic DA for better life cycle field applications.
Summary About one-half of the proven conventional oil reserves are in carbonate reservoirs. However, conducting surfactant flooding in these reservoirs presents several challenges, including formation heterogeneities, surfactant retention, high temperature and salinity, and oil-wet/mixed-wet conditions. Linear alkylbenzene sulfonates (LASs) are low-cost anionic surfactants that tend to precipitate in high-salinity environments and show high adsorption values in carbonate material. In this paper, the possibility of using petrochemical LASs of different alkyl chain lengths and isomer content to extract oil from carbonate reservoirs was tested using blends with the ionic liquid cocosalkylpentaethoximethylammonium methylsulfate (C1EG). Phase behavior, stability in the presence of divalent ions, and interfacial tension (IFT) measurements were the criteria used to design several optimal formulations containing 36–45% LASs. The structure-performance relationship was further assessed via static adsorption and wettability tests. LASs enriched in isomers with the benzenesulfonic group in external positions of the alkyl chain resulted in lower IFT but significantly higher adsorption, so those surfactants were discarded for the application. Additional oil recoveries achieved with tested formulations ranged from 36.7% to 43.5% of the residual oil in place. The longer the alkyl chain length, the higher the oil recovery. The main mechanism associated with improved oil recovery is IFT reduction. The use of a cost-effective ionic liquid derived from natural raw materials, the stability of the blends, the low adsorption of the chemical, and a significant oil recovery ensure the overall feasibility of the proposal.
Summary North Sea Chalk reservoirs in Norway are potential candidates for enhanced hydrocarbon recovery by modifying the injected brine composition. This work investigates how barium (Ba), strontium (Sr), and magnesium (Mg) brines interact when injected into chalk. Ba and Sr are often associated with mineral precipitation and occur in formation water, while Mg is present in seawater, commonly injected in chalk. Relatively clean (>99% calcite) outcrop chalk cores from Mons, Belgium, were flooded at 130°C in triaxial cells with four brines containing 0.12 mol/L divalent cations, either 0.06 mol/L Sr and Ba, 0.06 mol/L Sr and Mg, or 0.12 mol/L Ba or Sr. Each brine was injected in a separate core, with 100–150 pore volumes (PV). The injection rate varied between 0.5 and 8 PV/D. Produced brine was analyzed continuously and compared with the injected composition. After flooding, the cores flooded with only Ba or only Sr were cut into slices and analyzed locally in terms of scanning electron microscopy (SEM), matrix density, specific surface area (SSA), and X-ray diffraction (XRD). In all experiments, the produced divalent cation concentration was reduced compared with the injected value. The total reduction of injected cation concentration closely equaled the produced Ca concentration (from calcite dissolution). When flooding 0.12 mol/L Sr, the Sr concentration depleted 55%, while when flooding 0.12 mol/L Ba, 15% Ba depleted. When injecting equal concentrations of Ba and Sr, 40% Sr and 7% Ba depleted, while with equal concentrations of Mg and Sr injected, ~50% Sr was retained and almost no Mg depleted. Sr appeared to dominate and suppress other reactions. There was less sensitivity in steady-state concentrations with variation in injection rate. The similar modification of the brine regardless of residence time suggests the reactions reached equilibrium. Cutting the cores revealed a visually clear front a few centimeters from the inlet. The material past the front was indistinguishable from unflooded chalk in terms of density, SSA, microscale structure, porosity, and composition [XRD and SEM-energy-dispersive spectroscopy (EDS)]. The material near the inlet was clearly altered. Images, XRD, SEM-EDS, and geochemical simulations indicated that BaCO3 and SrCO3 formed during BaCl2 and SrCl2 flooding, respectively. Geochemical simulations also predicted an equal exchange of cations to occur. The matrix densities, porosities, and the distance traveled by the front corresponded with these minerals and suggested that the chalk was completely converted to these minerals behind the front. It was demonstrated that Ba, Sr, and Mg brines and their mixtures can be highly reactive in chalk without clogging the core, even after 100 + PV. This is because the precipitation of minerals bearing these ions is associated with simultaneous dissolution of calcite. The Ca-, Ba-, and Sr-mineral reactions are effectively in equilibrium. Previous investigations with MgCl2 (in pure and less pure chalk, at 130°C) show injection rate-dependent results (Andersen et al. 2022) and smoother alterations [Mg precipitation was seen from inlet to outlet (Zimmerman et al. 2015)], indicating that Mg-mineral reactions at same conditions have a longer time scale. The limited distance mineral alteration has occurred, suggesting that adsorption processes, happening in parallel, can explain previous observations (Korsnes and Madland 2017) of Ba and Sr injection strengthening chalk. Flushing out formation water with these ions during injection may be a new water-weakening mechanism.
If hydrogen is stored in depleted gas fields, the remaining hydrocarbon gas can be used as cushion gas. The composition of the backpro-duced gas depends on the magnitude of mixing between the hydrocarbon gas and the hydrogen injected. One important parameter that contributes to this process of mixing is molecular diffusion. Although diffusion models are incorporated in the latest commercial reservoir simulators, effective diffusion coefficients for specific rock types, pressures, temperatures, and gas compositions are not available in the literature. Thus, laboratory measurements were performed to improve storage performance predictions for an underground hydrogen storage (UHS) project in Austria. An experimental setup was developed that enables measurements of effective multicomponent gas diffusion coefficients. Gas con-centrations are detected using infrared light spectroscopy, which eliminates the necessity of gas sampling. To test the accuracy of the apparatus, binary diffusion coefficients were determined using different gases and at multiple pressures and temperatures. Effective dif-fusion coefficients were then determined for different rock types. Experiments were performed multiple times for quality control and to test reproducibility. The measured binary diffusion coefficients without porous media show a very good agreement with the published literature data and available correlations based on the kinetic gas theory (Chapman-Enskog, Fuller- Schettler-Giddings). Measurements of effective diffusion coefficients were performed for three different rock types that represent various facies in a UHS project in Austria. A correlation between static rock properties and effective diffusion coefficients was established and used as input to improve the nu-merical model of the UHS. This input is crucial for the simulation of backproduced gas composition and properties which are essential parameters for storage economics. In addition, the results show the impact of pressure on effective diffusion coefficients, which impacts UHS performance.
Summary Quantitative characterization of deep, tight, and heterogeneous reservoirs plays an important role in identifying hydrocarbon pathways for effective and optimal reservoir field development. In this case study, we used an azimuthal prestack seismic anisotropic inversion approach to estimate attributes of horizontal transverse isotropy (HTI) caused by a set of vertical fractures, oriented cracks, and stress. Anisotropic inversion facilitated the conversion of interface properties to the corresponding layer-based properties, which led to the quantitative interpretation of reservoir properties related to azimuthal variation in seismic amplitudes. To estimate the anisotropy magnitude and the direction of the isotropy axis in HTI media, elastic properties (P-impedance and Vp/Vs) obtained from prestack seismic inversion (using six azimuth × four angle stack) served as inputs. The isotropic low-frequency model (LFM) is used as the foundation of the inversion for all azimuths, and the anisotropy effects are later added by updating the model along the azimuths. The direction of the isotropy plane resulting from the anisotropic inversion is determined by using the maximum horizontal stress as a prior constraint, which eliminates any inherent uncertainty. The workflow used effectively characterized the orientation and density of fractures from the recently discovered oilfield reservoirs of the Paleocene (Lockhart) formation located in Pakistan’s north Potwar Basin. It also helped improve the prediction accuracy for fractures in the study area. According to the observations (fractures) from the exploratory drilled well (D1) in the tight carbonate (Lockhart) reservoir, a significant amount of anisotropy magnitude is observed. This provides the basis for hydrocarbon exploration, field development, and reliable drilling decisions.
Numerical simulation of the CO2 storage process in porous media, such as in hydrocarbon (gas or oil) depleted reservoirs and in saline aquifers, has been the most indicated tool due to its ability to represent CO2 capacity and the different trapping mechanisms that retain CO2 in the subsurface. Given the complexity of the physicochemical phenomena involved, the modeling needs to incorporate multiphase flow, complex representation of fluids, rock, and rock- fluid interaction properties. These include CO2 reactions with aqueous species and with reservoir rock minerals, in addition to the structural and stratigraphic aspects of the reservoir heterogeneity. These phenomena need to be represented on suitable temporal and spatial scales for accurate predictions of their impacts. Currently, many studies are focused on simulating submodels or sectors of the reservoir, where using finer grids is still practical. This level of grid refinement can be prohibitive, in terms of simulation times, for modeling the entire reservoir. To address this challenge, we propose a new and practical workflow to simulate CO2 storage projects in large field- scale models. When the proposed workflow is applied in both synthetic and real field cases, simulation time is reduced by up to 96% compared to that of the fine- grid model, preserving the same results in representing the aforementioned mechanisms. The workflow is based on classical and standard approaches to handle the high simulation time, but in this study, they are structured and sequenced in three steps. The first one considers the most relevant mechanisms for CO2 storage, ranked from a high- resolution sector model. With the mechanisms prioritized in the previous step, a single- phase upscaling of petrophysical properties can be applied in the field- scale model, followed by adopting a grid with dynamic sizing. The proposed methodology is applied to saline aquifer models in this study, but it can be extended for storage in depleted hydrocarbon reservoirs.
