Field Reservoir Research Articles

Impact of Paddy Field Reservoirs on Flood Management in a Large River Basin of Japan

The flood retention capacity of paddy fields is well-recognized in Japan, and all the existing flood control practices via paddy field management achieve reductions in peak flood discharge. However, the previous studies have not assessed the flood management potential of paddy fields in a large river basin with average paddy coverage, and the existing hydrological models are not quite suitable for simulating river discharge from closed-drainage paddy reservoir storage. We herein attempt to improve the watershed-scale version of global hydrological model H08 to simulate a reduction in the peak discharge from paddy reservoirs in the Abukuma River basin of Japan. The NSE and R2 index showed fair reliability of the H08 model during the calibration and validation stages. The simulated results from the improved model show 11% and 6% peak reductions in high paddy coverage areas for a normal year (2018) and a major typhoon year (2019), respectively. The peak-reduction percentage increased with decreasing rainfall, depending on the overflow from the paddy reservoirs. The results indicate that the paddy reservoir is not highly effective in a large river with less than 20% paddy coverage, but the peak discharge reduction capacity shows that paddy reservoirs can make some contribution when used in combination with dam operation.

A technology for monitoring the onset of malfunctions in oil field reservoir pressure maintenance equipment

Existing control and management systems of oil field reservoir pressure maintenance equipment do not warn of the beginning of the latent period of accidents. At the same time, accidents are preceded by the emergence of certain defects, followed by their latent period, after which they develop. Only after that they begin to affect the readings of measuring instruments of control and management systems. The duration of the latent period depends on the dynamics of defect development. Because of the above, control systems detect the beginning of an emergency when it becomes explicit. This leads to unreasonable costs, since elimination of the defect at the moment of its origin requires much less funds and time than after-accident pump repairs. It is shown in the paper that as a result of continuous rotational motion under high pressure, a vibration process is inevitably formed in this equipment, and the beginning of the latent period of malfunctions makes a clear impact on their noisy vibration signals, with a correlation emerging between the noise and the useful component. To control the beginning of malfunctions in reservoir pressure maintenance equipment it is proposed to use the estimates of noise variance and cross-correlation functions between the useful signal and the noise, which allow forming informative attributes for warning and control of the beginning of the latent period of malfunctions. The proposed technologies can also be used to improve accident-free operation at compressor stations of main oil and gas pipelines, at drilling rigs, at artesian wells, in transport, etc.

Study and application of temporary plugging agent for temporary plugging acid fracturing in ultra-deep wells of Penglai gas field

The burial depth of Penglai gas field reservoir in the Sichuan Basin of China exceeds 7,000 m, and the reservoir temperature is 160°C. Penglai gas field belongs to the fractured reservoir, and there are many natural fractures distributed in the reservoir. Natural fractures are not only the storage place of natural gas, but also the transportation channel of natural gas. Gas wells mainly increase natural gas production through acid fracturing. In the early stage, Penglai Gas Field mainly used gelled acid fracturing technology to create an artificial fracture in the reservoir by injecting a large amount of acid fluid. However, the stimulation range of gelled acid fracturing is very small. After acid fracturing, gas wells can only produce 120,000 cubic meters of natural gas per day. To obtain higher natural gas production, this paper proposes a multi-stage temporary acid fracturing technology that can greatly improve the effect of acid fracturing. The temporary plugging agent for acid fracturing has been developed to meet the high-temperature requirements of the Penglai gas field. Based on the simulation of fracture propagation, the feasibility of acid fracturing expansion of natural fractures in the Penglai Gas Field is clarified. Fiber and granular temporary plugging agents that meet the plugging strength greater than 20 MPa are selected by using the dynamic temporary plugging instrument. MultiFracS software is used to optimize the multi-stage temporary acid fracturing process parameters. The research results in this paper have been applied to wells PS101, PS102, and PS103. After fracturing, compared with the gelling acid fracturing, the natural gas production has increased by more than three times, and the multi-stage temporary plugging acid fracturing has achieved a very good stimulation effect.

Elastic response of porous rock to accumulated slip on strike slip fault networks in geo-reservoirs

Subsurface reservoirs are generally highly fractured, whereby fractures constitute a natural fluid flow path and define the preferential flow direction. Slip accumulated during the faulting process alters also the petrophysical properties of the host rock. Although the mechanical alteration of the host rock, and related porosity and permeability changes, due to fault slip has been previously described, a predictive physics-based model has not been scaled with fault length in reservoirs to provide an initial porosity permeability alteration model yet. In this study, we develop a predictive model to quantify how accumulated fault slip changes porosity and permeability in a porous medium, by combining deformation modeling based on triangular dislocations and linearized poro-elasticity equations. We applied our model the Ghawar field fault map and rock-types. We conducted a Monte-Carlo simulation, varying fault roughness and accumulated slip, to quantify the corresponding variation in porosity and permeability using a 5 km long strike-slip fault and three different rock-types. Our Monte-Carlo simulation shows that long-term accumulated slip on rough strike-slip fault surfaces change porosity by ±1%, leading to an absolute permeability change of up to 22.5%. We further used these results as a benchmark for the elastic response of porous rocks to accumulated slip scaled to certain fault length. Using these benchmark results for Ghawar field reservoir rocks, we determined the slip-related porous medium permeability changes for every fault on the Ghawar fault map, accounting for their length, location, and orientation. In doing so, we found that fault roughness, slip amount, and shear sense all affect the medium’s permeability, creating substantial permeability anisotropies. Locally, these anisotropies are further enhanced by superposition of permeability changes of individual faults that constitute the fault system. We suggest the resulting permeability distribution model should be used as the initial permeability model for porous media in fractured reservoirs.

Petrographic recognition and classification of bioclastic carbonate thin sections based on attention mechanism

The huge reserves of carbonate reservoirs have become an important target for oil and gas exploration and development, but their complex pore structure makes petrographic identification difficult, while the traditional identification and classification process using manual analysis of rock thin sections suffers from problems such as being susceptible to subjective factors and being time-consuming. To address these problems, this paper proposes a new method for the intelligent classification of thin sections based on an attention mechanism. Firstly, 295 original images of carbonate reservoirs in the Haffaya oil field of Iraq in the Middle East are used for training to obtain a network model that can directly use rock thin sections images as input variables for analysis of the classification network. It was then classified into seven categories according to Dunham's classification method and compared with the ResNet classification network. The results show that the combined accuracy of the method is 13.8% higher than that of the ResNet network, reaching 93.6%; it can effectively extract the relevant characteristics of rock thin sections under the condition of small sample data, and has strong applicability in complex carbonate reservoirs.

A new numerical well test method of multi-scale discrete fractured tight sandstone gas reservoirs and its application in the Kelasu Gas Field of the Tarim Basin

The cretaceous gas reservoir in Kelasu Gas Field of the Tarim Basin is a rare ultra-deep and ultra-high pressure fractured tight sandstone gas reservoir where multi-scale discrete fractures of matrix, fracture and fault are developed, so its development cannot be conducted just based on static and dynamic reservoir description. In order to solve this problem, this paper establishes a numerical well test model of vertical wells based on matrix, fractures and faults (large fractures and small faults) by combining the random generation of natural fracture networks with the unstructured discrete fracture modeling method to break through the traditional continuous medium well test model. In addition, the model is solved by using the finite element method with mixed element, and the typical well test type curves under different random fracture networks are obtained. And the following research results are obtained. First, based on the observed data, the fracture network distribution modes of fractured tight sandstone gas reservoirs are classified into three categories. The influence of random generation of fracture networks on typical well test type curves is discussed. The results of discrete fracture well test model are compared with those of the traditional continuous medium well test model, and the applicable conditions of the traditional continuous medium well test model is determined. Second, there are great differences between the results of discrete fracture model and those of dual porosity medium model. 1 The dual porosity medium model is a special case of the discrete fracture model, in which the fractures are evenly distributed within infinitely small spacing. Third, the characteristics of well test type curves under three fracture network distribution modes are discussed. The well test type curves that cannot be interpreted by the conventional dual/triple porosity continuous medium model are successfully interpreted by using the established well test interpretation model of random discrete fracture. The curve matching effect is ideal and the interpreted parameters are reasonable. In conclusion, the new model and the new method reveal the development mechanism of step-by-step production and coordinated gas supply between media of different scales, explain the development characteristics of large inter-well productivity difference and abnormal rapid inter-well pressure response, and provide a reference for the development of similar gas reservoirs.

Integrated Geological and Petrophysical Approaches for Characterizing the Pre-Cenomanian Nubian Sandstone Reservoirs in Ramadan Oil Field, Central Gulf of Suez, Egypt

The present study integrates multidisciplinary geological and petrophysical approaches to characterize and evaluate the potential of the pre-Cenomanian Nubian sandstone reservoirs in the Ramadan oil field, the central offshore part of the Gulf of Suez, Egypt. The different petrophysical parameters of the Nubian sandstone reservoirs (shale volume, porosity, water saturation as well as gross and net-pay thicknesses) were mapped, and 3D slicing models for the hydrocarbon phases saturation were constructed to understand the reservoir heterogeneity and the distribution of the best reservoir facies. The petrophysical results of the pre-Cenomanian Nubian succession highlight very good reservoir intervals in the Nubian C sandstones containing thick pay zones (> 120 m). On the other side, the Nubian A and B reservoir rocks are less prospective with pay zone horizons (< 10 m). Integrated reservoir models and wireline log analysis elucidate that clay volume is the most detrimental factor to the reservoir quality as the pay zone thickness and hydrocarbon saturation often increase where the clay volume decreases. Therefore, the presence of scattered pay zone intervals in Nubian A and B is mainly related to their elevated clay content which acts as barriers for fluids flowing within the reservoir facies. The Nubian C succession contains three different reservoir rock types (RRT) with variable compositional and petrophysical properties. RRTI and RRTII sandstones comprise quartzose sandstones with very low clay content (< 10%) and are characterized by an open pore system dominated by macropores. These sandstones are less impacted by overburden pressure and therefore can preserve their depositional porosity and permeability. On the other hand, RRTIII reservoir rocks are clay rich (> 10%) with abundant mesopores that are more prone to compressibility and hence reduction of the pore volume and pore throat. The present study highlights the significance of comprehensive integration between wireline logs, cores, and 3D reservoir models in directing exploration endeavors toward prospective reservoirs in mature basins.

Permeability prediction using logging data in a heterogeneous carbonate reservoir: A new self-adaptive predictor

Accurately predicting permeability is critical for oil deposit exploitation and high-quality reservoir identification. However, the substantial heterogeneity in carbonate reservoirs has significantly challenged the accurate permeability prediction. In this study, 325 core samples with logging data from the Sinian carbonate reservoirs of the second member of the Dengying Formation were collected to establish a reliable predictor for permeability prediction in the Gaoshiti-Moxi block, Sichuan Basin. Three typical machine learning algorithms and three population-based optimization algorithms were applied to the core samples and logging data to evaluate the applicability and prediction performance of different methods. Two types of objective functions are well designed to obtain a more satisfactory result for permeability prediction. By comparison, the multi-objective mayfly algorithm (MMA) combined with gradient boosting decision tree (LGB) among all the algorithms had a more vital ability to predict permeability. Therefore, a new self-adaptive predictor was developed by combining the MMA-LGB algorithm with the low-pass filters that were applied as a noise filtering method from the original geophysical well logs with Fourier transform (FT). Filtered logs were tested by using Fractal statistics. Through comparisons, the self-adaptive predictors significantly improved the prediction accuracy with the lowest MSE of 0.239 and the highest R2 of 0.831, well demonstrating that combining the machine learning algorithm with low-pass filters could mitigate the adverse effects of heterogeneity on permeability prediction. The excellent prediction performance of the proposed self-adaptive predictor lays a sound theoretical foundation for logging interpretation and identifying high-quality carbonate reservoirs in the target field.

Karst thermal reservoir tracer test and seepage characteristics analysis in Niutuozhen geothermal field in Xiong’an New Area

The carbonate rock karst thermal reservoir in the Niutuozhen geothermal field is a high-quality geothermal resource with significant development potential. However, due to the strong heterogeneity of karst thermal reservoirs, the connectivity between recharge and production wells is hard to determine, which seriously restricts the sustainable development of the Niutuozhen geothermal field. Therefore, this study revealed the hydraulic connection between the recharge and production well through the tracer test, quantitatively characterized the seepage characteristics of the reservoir combined with the numerical simulation, and proposed the deployment of the recharge well. The results show that the total recovery rate of the tracer is 0.42%, indicating that there are a small number of communication channels with a good hydraulic connection between the recharge and production well in the experimental area, and the recharge will not cause thermal breakthrough within a short time period. The velocity of recharge water can reach 359 m/d at the fastest, and the directions of dominant channels are concentrated in the NW, N, and E directions centered on the recharge well, this is consistent with the characteristics of regional fractures, recharge wells should be avoided to deployed in those directions. The results provide effective information for the prediction of the thermal breakthrough time and the accurate establishment of the thermal reservoir model in the Niutuozhen geothermal field, also provide a scientific basis for the sustainable utilization of the carbonate karst thermal reservoir geothermal resources.

Compatibility Coreflood Studies Explore Formation Damage in Tight Reservoirs

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 207764, “Case Study of Identifying and Minimizing Formation Damage in Tight Reservoirs Caused by Drilling Fluids in Abu Dhabi Onshore Operation Using Compatibility Coreflood Studies,” by Raymond Saragi, Mohammad Husien, and Dalia S. Abdullah, ADNOC, et al. The paper has not been peer reviewed. _ The authors examine formation-damage mechanisms caused by drilling fluids in tight reservoirs in several onshore Abu Dhabi oil fields. Three phases of compatibility corefloods were performed to identify the potential of improving hydrocarbon recovery and examine reformulated or alternate drilling muds and treatment fluids. The compatibility corefloods on tight reservoir cores, along with high-resolution quantifications and visualizations, identified damaging mechanisms and helped identify potential to improve hydrocarbon recovery and treatment-fluid options. Introduction The operator examined drilling-mud performance for UAE fields including Bab, Rumaitha, Qusahwira, Sahil, and Mender. Results appeared to be good in high-permeability zones but not in lower-permeability zones. A multiphase compatibility study consisting of a series of coreflood simulations analyzed both producer and injector wells, but the complete paper focuses on the producer wells. The use of nano-computed tomography (CT) scans and cryogenic scanning electron microscope (SEM) with energy dispersive spectroscopy (EDS) as interpretative tools provided insights into the coreflood results (55 of which are presented in the complete paper). The reservoirs consist of Lower Cretaceous carbonate sediments. This study examined lower-permeability zones; the results shown in the complete paper are only from the tight samples below 15 md. The samples used in the study are detailed in Table 1 of the complete paper and represented the following reservoirs: - Bab (wells coded BB-1, BB-2, BB-3, BB-4, BB-5, BB-6, and BB-7; 0.1–15-md gas permeability) - Mender (well coded MN-1; 3–12-md gas permeability) - Qusahwira (wells coded QW-1 and QW-2; 0.5–1-md gas permeability) - Rumaitha (well coded RA-1; 2–15-md gas permeability) - Sahil (well coded SA-1; 2–4-md gas permeability) Methodology Coreflood simulations were performed using specialized equipment capable of executing the study at reservoir conditions while eliminating artifacts such as corrosion. Accurate replication of reservoir conditions is important, especially where potential scaling exists. Phase 1 examined permeability alterations and damaging mechanisms after application of the currently used drilling mud. The methodology is detailed in the complete paper, but the authors emphasize the use of interpretive tools in this process. Phase 2 examined a series of reformulated and alternate drilling muds. Following the results of Phase 1, the current field mud was reformulated and examined as Reformulated Mud Formulation 1 alongside three alternate drilling muds from separate vendors. Phase 3 built on Phases 1 and 2 by examining the incorporation of a displacement or treatment fluid as part of the operational sequence. The methodology for Phase 3 was similar to that used in the previous phases, with the addition of treatment-fluid application before drawdown.

3D Geological Model for Zubair Reservoir in Abu-Amood Oil Field

The Zubair reservoir in the Abu-Amood field is considered a shaly sand reservoir in the south of Iraq. The geological model is created for identifying the facies, distributing the petrophysical properties and estimating the volume of hydrocarbon in place. When the data processing by Interactive Petrophysics (IP) software is completed and estimated the permeability reservoir by using the hydraulic unit method then, three main steps are applied to build the geological model, begins with creating a structural, facies and property models. five zones the reservoirs were divided (three reservoir units and two cap rocks) depending on the variation of petrophysical properties (porosity and permeability) that results from IP software interpretation. Five wells that penetrate the lower Cretaceous Formation (Zubair reservoir) are used to construct the geological model. ZUB-1 unit considered as the most important zone which have a good petrophysical parameters about 24% for porosity, 800 md permeability, 38% water saturation and 85% net to gross. The initial oil in place is estimated to be about 1.7898*109 STB. Finally, 3D geological model support in improving and estimates the hydrocarbon potentialities in oil field and enhances the production of the field.

Estimation of Petrophysical Properties for Zubair Reservoir in Abu-Amood Oil Field

The petrophysical analysis is significant to determine the parameters controlling the production wells and the reservoir quality. In this study, Using Interactive petrophysics software to analyze the petrophysical parameters of five wells penetrated the Zubair reservoir in the Abu-Amood field to evaluate a reservoir and search for hydrocarbon zones. The available logs data such as density, sonic, gamma ray, SP, neutron, and resistivity logs for wells AAm-1, AAm-2, AAm-3, AAm-4, and AAm-5 were used to determine the reservoir properties in Zubair reservoir. The density-neutron and neutron-sonic cross plots, which appear as lines with porosity scale ticks, are used to distinguish between the three main lithologies of sandstone, limestone, and dolomite. The corrected gamma ray log was used in all wells to determine the shale volume. Neutron-sonic log was used to calculate porosity at the reservoir unit while sonic log was employed to estimate the porosity at poor hole conditions and (non- reservoir units). Furthermore, the Indonesia model was used to calculate water saturation in Zubair reservoir and compared with the Archie model. Finally, Flow zone indicator method was used for permeability evaluation. The results show that the Zubair reservoir is primarily consists of sandstone, shale with compacted limestone, which was improved by the cuttings description report. The core porosity was validated in AMM-1, AMM-2, AMM-3and AMM-5 wells. Indonesia equation provides an optimum estimation in shaly sand zones since the Archie model takes the matrix conductive and the fluid conductivity into account. Four hydraulic flow units produced from reservoir quality index against normalized porosity index cross plot and obtained Four equations from porosity- permeability relationship of core data. The general interpretation presented that the most of hydrocarbons are located in depth (3332.8 m to 3415.8 m) which represents the best layer in Zubair reservoir, the properties of this layer in well AMM-1better than in well AMM-2. Finally, the layer from 3574.8 m to3638.3 m supposed to be water layer rather than hydrocarbon layer.

Development of 3D Geological Model and Analysis of the Uncertainty in a Tight Oil Reservoir in the Halfaya Oil Field

A geological model was built for the Sadi reservoir, located at the Halfaya oil field. It is regarded as one of the most significant oilfields in Iraq. The study includes several steps, the most essential of which was importing well logs from six oil wells to the Interactive Petrophysics software for conducting interpretation and analysis to calculate the petrophysical properties such as permeability, porosity, shale volume, water saturation, and NTG and then importing maps and the well tops to the Petrel software to build the 3D-Geological model and to calculate the value of the original oil in place. Three geological surfaces were produced for all Sadi units based on well-top data and the top Sadi structural map. The reservoir has been divided into 85 sublayers in the vertical direction and 170*143 grid cells in the x-y direction, totalling 2,066,350 grid cells. The Sequential Gaussian Simulation technique is used to fill 3D grid cells with property values in locations far from wells after upscaling the well log data, then distributed across all reservoir zones. The standard original oil in place has been calculated, uncertainty evaluation was used to obtain more accurate results. Model Risk Analysis employs Monte Carlo Simulation to generate the pessimistic, most likely, and optimistic reserve values (P90, P50, and P10). The uncertainty was affected by the oil formation volume factor, oil depth, petrophysical model (porosity, water saturation, and NTG), and reservoir geometric structure (horizons and zones).

Stationary states of a dissipative two-qubit quantum channel and their applications for quantum machine learning

Entangled-state preparation and preservation are the cornerstones of any quantum information platform. However, the strongest adversaries in quantum information science are unwanted environmental effects such as decoherence and dissipation. Here, we address how to control and harness these unwanted effects that arise from the coupling of a system with its environment, to provide stationary entangled states for quantum machine learning (QML). To do so, we design a dissipative quantum channel, i.e., a two-qubit system interacting with a squeezed vacuum field reservoir, and study the output state of the channel by solving the corresponding master equation, especially, in the small squeezing regime. We show that the time-dependent output state of the channel is the so-called two-qubit X-states that generalize many families of entangled two-qubit states. Also, by considering a general Bell diagonal state as the initial state of the system, we reveal that this dissipative channel generates two well-known classes of entangled mixed state and Werner-like states in the steady-state regime. Moreover, this channel provides an efficient way to determine whether a given initial state results in a stationary entangled state or not. Finally, we examine the potential application of the designed two-qubit channel for QML. In this line, we propose a general theoretical scheme for quantum neural networks (QNNs) implemented with the variational quantum circuits, which encode data in continuous variables (CVs) of the two-qubit states. The linear (also referred to as affine) and nonlinear (activation function) transformations are enacted in the QNN using the stationary states of the two-qubit channel and measurement process, respectively. Finally, we proceed to test our proposed model by solving some supervised binary classification tasks. Integrating the non-unitary transformation and parallel-processed neural computing on such a two-qubit channel establishes the requirements for a meaningful QNN. Such a CV-QNN model with sufficient layers may execute any algorithm implementable on a universal CV quantum computer.

Magnetized granular particles running and tumbling on the circle S^{1}.

It has been shown that a nonvibrating magnetic granular system, when fed by an alternating magnetic field, behaves with most of the distinctive physical features of active matter systems. In this work, we focus on the simplest granular system composed of a single magnetized spherical particle allocated in a quasi-one-dimensional circular channel that receives energy from a magnetic field reservoir and transduces it into a running and tumbling motion. The theoretical analysis, based on the run-and-tumble model for a circle of radius R, forecasts the existence of a dynamical phase transition between an erratic motion (disordered phase) when the characteristic persistence length of the run-and-tumble motion, ℓ_{c}<R/2, to a persistent motion (ordered phase) when ℓ_{c}>R/2. It is found that the limiting behaviors of these phases correspond to Brownian motion on the circle and a simple uniform circular motion, respectively. Furthermore, it is qualitatively shown that the smaller the magnetization of a particle, the larger the persistence length. It is so at least within the experimental limit of validity of our experiments. Our results show a very good agreement between theory and experiment.

Factors controlling the distribution of granite reservoirs of hydrothermal system type in South China: A case study of Huangshadong geothermal field in Yuezhong Depression, China

The granitoids widely distributed in South China are characterized by multi-stage evolution via episodic intrusions, in a complex geodynamic setting. Since granites have high radioactive heat generation and excellent thermal conductivity, a deep moderate- to high-temperature geothermal system can be formed in the presence of high-quality, fissured granite geothermal reservoirs and thermal insulation with appropriate cap rocks. The key to exploring deep geothermal resources is to identify high-quality fissured granite geothermal reservoirs of a certain scale in a thermal anomaly zone with high background heat-flow values. To determine the controlling effects of the distribution and development characteristics of granite geothermal reservoirs on the generation and enrichment of deep geothermal resources, this study analyzed the characteristics of the geothermal reservoirs in the Huangshadong geothermal field in the Yuezhong Depression, Guangdong Province, and their controlling effects on the formation of geothermal resources. The results are as follows. The hydrothermal system in the Huangshadong geothermal field mainly distributed in the contact zones between magmatic plutons and surrounding rocks, is significantly controlled by faults, followed by neoid volcanic apparatus and magmatic activities. That is, the geothermal system therein is under joint control of structures and magmas. Moreover, fractured zones of neoid transtensional faults conduct the geothermal water in the hydrothermal system and control its shallow discharge. Therefore, the hydrothermal system in the study area is characterized by the control of transpressional tectonic zone and volcanic apparatus, and geothermal water conduction through fractured zones of transtensional faults.

Enigmatic Reservoir Properties Deciphered Using Petroleum System Modeling and Reservoir Fluid Geodynamics

Two adjacent reservoirs in offshore oil fields have been evaluated using extensive data acquisition across multiple disciplines; several surprising observations were made. Differing levels of biodegradation were measured in the nearly adjacent reservoirs, yet related standard geochemical markers are contradictory. Unexpectedly, the more biodegraded oil had less asphaltene content, and this reservoir had some heavy end deposition in the core but upstructure, not at the oil-water contact (OWC) as would be expected, especially with biodegradation. Wax appears to be an issue in the nonbiodegraded oil. These many puzzling observations, along with unclear connectivity, gave rise to uncertainties about field development planning. Combined petroleum systems and reservoir fluid geodynamic considerations resolved the observations into a single, self-consistent geo-scenario, the co-evolution of reservoir rock and fluids in geologic time. A spill-fill sequence of trap filling with biodegradation helps explain differences in biodegradation and wax content. A subsequent, recent charge of condensate, stacked in one fault block and mixed in the target oil reservoir in the second fault block, explains conflicting metrics of biodegradation between C7 vs. C16 indices. Asphaltene instability and deposition at the upstructure contact between the condensate and black oil, and the motion of this contact during condensate charge, explain heavy end deposition in core. Moreover, this process accounts for asphaltene dilution and depletion in the corresponding oil. Downhole fluid analysis (DFA) asphaltene gradients and variations in geochemical markers with seismic imaging clarify likely connectivity in these reservoirs. The geo-scenario provides a benchmark of comparison for all types of reservoir data and readily projects into production concerns. The initial apparent puzzles of this oil field have been resolved with a robust understanding of the corresponding reservoirs and development strategies.

WITHDRAWN:Prediction of Permian karst reservoirs in the Yuanba gas field, northern Sichuan Basin, China

WITHDRAWN:Prediction of Permian karst reservoirs in the Yuanba gas field, northern Sichuan Basin, China

Geological Model for Jeribe/Euphrates Formation, Tertiary Reservoir in Qaiyarah Oil Field, North of Iraq

Visualization of subsurface geology is mainly considered as the framework of the required structure to provide distribution of petrophysical properties. The geological model helps to understand the behavior of the fluid flow in the porous media that is affected by heterogeneity of the reservoir and helps in calculating the initial oil in place as well as selecting accurate new well location. In this study, a geological model is built for Qaiyarah field, tertiary reservoir, relying on well data from 48 wells, including the location of wells, formation tops and contour map. The structural model is constructed for the tertiary reservoir, which is an asymmetrical anticline consisting of two domes separated by a saddle. It is found that the three formations in the tertiary reservoir is composed of limestone and dolomitic limestone with very thin shale rims introduced only in the Dhiban Formation, which have the minimum thickness compared to the main other two formations those considered the main reservoir units. Upscaling from the software has been used to distribute and correlate between the logs and core data, which came very acceptable results to be used for distribution to the entire field. Both log analysis and core data have showed that the reservoir is clean formation, no volume of shale has considered in the STIIOP calculations with average water saturation calculated to be 31.5% and average porosity of approximately 22% with temperature gradient of 1.2 °F/100 ft. This comes up with Stock Tank Initial Oil in Place calculated to be 6.519*109.

Diffusion Effect on Shale Oil Recovery by CO2 Huff-n-Puff

The CO2 diffusion effect is an important mechanism of injected CO2 penetrating the reservoir matrix and diffusing into the oil phase during the huff-n-puff (HNP) process. However, the CO2 diffusion coefficient of shale is still uncertain under the reservoir conditions, and the contribution of diffusion to enhanced oil recovery (EOR) needs to be further explored. In this study, the CO2 diffusion coefficient of shale is determined under the simulated reservoir conditions (9–10 MPa, 90 °C) in the laboratory, and the determined CO2 diffusion coefficient is applied in the reservoir numerical model to evaluate the contribution of the CO2 diffusion effect to EOR in the HNP process. First, a radial constant volume diffusion (RCVD) device was built to measure the CO2 diffusion coefficient by the pressure decay method. After that, both the analytical solution and the numerical solution are used to ensure that the result is correct. Finally, a field-scale model consisting of one stage of hydraulic fracture in a shale oil reservoir is established. The effects of reservoir properties such as fracture spacing, fracture half-length, and operational properties of HNP like injection rate, injection time, and soaking time on oil recovery were discussed when the diffusion was included and excluded. The CO2 diffusion coefficient of a shale core is ranging from 1.44 × 10–7 to 5.50 × 10–7 cm2/s, and it is reasonable to be applied in the field reservoir numerical simulation model. According to simulation results, the lower fracture spacing and longer fracture half-length make more CO2 diffuse into the shale matrix, which are critical parameters, to promote the CO2 diffusion effect. When the injection rate is slow and the injection time is short, the CO2 diffusion effect in the reservoir may contribute more to EOR. A high injection rate means sufficient pressure supplement, and the CO2 diffusion effect may become relatively negligible. The soaking time may not be necessary for the EOR of HNP, but the longer soaking time will promote the contribution of CO2 diffusion to EOR, and the incremental recovery is about 0.15–0.26%.