Reservoir Rock Properties Research Articles

Research on improving permeability of granite reservoir: Polyhydrogen chelating acid acidizing

ABSTRACT Acidization is a highly effective technique for increasing oil well productivity. Therefore, it is critical to study effective stimulation of low-permeability granite reservoirs using acidification. Using the granite reservoir of Baobab oilfield in Chad as the research object, the properties of reservoir rocks were tested using XRD and rock thin section analysis. Dissolution experiments, core flooding experiments, and CT scanning were used to investigate the increased permeability and changes in the pore structure of the cores during acidification. The minerals in the rocks are primarily plagioclase, kalifeldspar, and quartz, with trace amounts of calcite, chlorite, magnetite, illite, biotite, hornblende, sphene, and sericite. At 80°C and 10 mL of main acid injection, polyhydrogen chelating acid (6% HCl + 5% SA601 + 7% SA701) improved granite permeability more than mud acid (8% HCl + 2% HF) and fluoroboric acid (8% HCl + 8% HBF4), with permeability increase of 3.68. The CT three-dimensional images of the rocks show that both the cores acidified with polyhydrogen chelating acid and mud acid formed continuous acid-etched wormholes, while the cores acidified with fluoroboric acid did not. Compared to the mud acid, the core acidified by the polyhydrogen chelating acid produced more visible acid-etched wormholes. Meanwhile, the polyhydrogen chelating acid was more effective at improving the pore throats and expanding the flow channels in the core. This study serves as a reference for the application of acidification and increasing production in low-permeability granite reservoirs.

تصميم نظام غمر المياه لحقل الدفا النفطي

Currently, water-flooding is responsible for a big portion of world oil production. The vertical sweep efficiency and the areal coverage each of these requires careful sampling to get represented reservoir rock and fluid properties measures of reservoir heterogeneity, Economically, a pilot is a desirable tool for studying oil recovery performance on reservoir sample and then scaled up to yield the performance to be expected from field performance. Defa field was produced since 1968 with good oil flow rate reaching 200,000 BOPD but during the life of the field, the production decreased to 50,000 BOPD in 2001. So, this study was conducted to increase oil production by add some energy to the reservoir to increase average reservoir pressure and try to maintain it to initial pressure and to increase displacement and sweep efficiency. The water flooding design was implemented in sector model in the Defa field using five spots pattern. The study was performed by using Excel and Water Drive software to achieve a good water flooding design. When comparing the results obtained from two calculation methods, the minimum error was equal 0.03 percent and the maximum error was around 12 percent. So, the results were acceptable and the process was recommended to the Defa-field. Keywords: Water flooding; Software; Fractional Flow, Break through.

Modified Low-Field NMR Method for Improved Pore Space Analysis in Tight Fe-Bearing Siliciclastic and Extrusive Rocks

Abstract Understanding the filtration and storage properties of tight reservoirs is crucial for efficient resource exploitation, particularly in unconventional formations. This study presents two low-field nuclear magnetic resonance (LF-NMR) techniques: standard cut-off and modified differential approaches combined with mercury injection capillary pressure (MICP) and X-ray diffraction (XRD) studies to evaluate porosity and pore size distribution (PSD) in such formations. The differential technique involves subtracting the dry sample signal from a 100% water-saturated one, allowing the chemically bound water compound to be eliminated and facilitating PSD analysis. Through the application of the percolation theory, we established a power–law relationship between LF-NMR transverse relaxation time (T2) and MICP pore-throat diameter, enabling the derivation of PSD and pseudo capillary pressure curves. Our methodology was validated on a sample set representing tight sandstones, conglomerates, and extrusive rocks with high clay and iron mineral content, demonstrating the superior accuracy of the modified differential method in estimating effective porosity and absolute PSD in comparison with the standard approach. While the use of the percolation theory in PSD conversion was successful for rocks with unimodal distributions, it often failed for rocks with larger voids. The study also revealed that the relationship between the LF-NMR transverse relaxation times and MICP pore sizes is both nonlinear and challenging to describe with a universal equation, especially in the presence of para- and ferro-magnetic elements in the rock matrix. Despite obstacles to the complete elimination of the influence of these minerals on the T2 distribution, employing the modified differential LF-NMR method significantly mitigated this effect and offered a precise and noninvasive way of characterizing the petrophysical properties of tight reservoir rocks. Consequently, our studies offer a significant step toward a more precise assessment of pore structures in unconventional reservoirs that could be translated into more efficient strategies for locating geothermal heat and hydrocarbon resources.

A data-driven dual-optimization hybrid machine learning model for predicting carbon dioxide trapping efficiency in saline aquifers: Application in carbon capture and storage

Geological carbon sequestration (GCS) is a promising method to reduce global carbon emissions. To better understand the CO2 trapping mechanism, the CO2 sequestration process was simulated through a physics-based reservoir simulator, and the residual trapping (RTI) and solubility trapping (STI) efficiencies were analyzed. Through the experiments, a database containing 4543 data points with reservoir physical parameters and rock properties was established. In this study, a kernel extreme learning machine (KELM) model based on variational mode decomposition (VMD) and dung beetle optimization optimizer (DBO) was proposed to perform the prediction task. Through the VMD, the original data sequences were decomposed and combined, and the obtained subsequences were executed modeling prediction and reconstruction respectively. The reliability of the prediction model was confirmed to be greater than 97.71% through domain analysis. In addition, it was applied to a tight gas reservoir in China in to confirm its validity in field applications. Comparative results indicated a high agreement between the prediction results and the simulation results, suggesting that the proposed method can complement numerical simulations and help users understand the application of machine learning in carbon capture and storage (CCS).

Tree-Based Machine Learning Can Determine Lithofacies Properties of Reservoir Rocks- Camal Oil field, Yemen

Tree-Based Machine Learning Can Determine Lithofacies Properties of Reservoir Rocks- Camal Oil field, Yemen

Effect of secondary processes on the petrophysical properties of sand rock of the tanopchin formation of the Tambey field (Yamalo-Nenets autonomous okrug)

Relevance. Finding the correlation between filtration-capacitive properties and secondary processes helps to identify missed oil and gas deposits. Traditional methods of processing geophysical information are becoming less and less effective, and accordingly there is a need to introduce new techniques for detecting missed hydrocarbon deposits. Aim. To study the effect of secondary processes on the filtration and reservoir properties of rocks in the productive lower strata of the tanopchin formation of the North Tambey license area, located within the Tambey field, using materials from geophysical surveys of wells and core data. Methods. The statistical-correlation interpretation method represents a significant breakthrough in the field of interpretation of well logging data. It allows for a more accurate interpretation of data from existing reservoir studies, which makes it possible to identify productive sections of wells where hydrocarbons could not be detected by traditional methods. Statistical correlation interpretation is carried out on the basis of data from secondary geochemical processes occurring in the formation. The scientific novelty. Identification of the relationship between the intensity of secondary processes and the petrophysical properties of the rocks of the Lower Cretaceous productive horizon of the Tambey field (Yamalo-Nenets autonomous okrug). Results and conclusions. The author has determined the dependence of the filtration-capacitive properties of rocks on the intensity of secondary geochemical processes. It was established that secondary geochemical processes such as carbonatization and pyritization worsen reservoir properties, while kaolinization and pelitization lead to an improvement in the filtration and reservoir properties of reservoir rocks. The paper explains the mechanism of effect of secondary processes on filtration-capacitive properties. Pelitization of potassium feldspars leads to the formation of three-layer clay minerals, which have the largest sorption surface area and cation exchange capacity; as a result, the reservoir capacity increases, which leads to an increase in permeability several times.

Modifying the Effects around the Well can have an Impact on the Drilling Process

Environmental changes around a well can significantly affect the drilling process. This paper examines the effects of flow rate, bottomhole pressure, sheet permeability, viscosity, pressure gradient and well radius on the drilling process. It is shown that the energy-dynamic instability of the sheet’s near-shiva space, a highly active region in the formation, leads to changes in reservoir rock and fluid properties during the drilling process. These changes include physicochemical transformations such as deposition of asphaltenes, paraffins, and resins, as well as swelling of clay particles, which can disrupt reservoir physical properties and affect hydrocarbon flow. In addition, completion and production techniques and the chemistry of drilling and pressure fluids are particularly critical for low-permeability reservoirs. In this paper, the concept of skin effect is also introduced to assess the impact of process fluids on the bottomhole region, and a new assessment model is proposed. The results of the study are important for improving drilling technology and optimising reservoir development.

Burial of a sand sea: Heterogeneous compaction and cementation of the jurassic Etjo Formation, Namibia and what it tells

Aeolian sandstones are capable of forming excellent reservoir rock due to their textural and compositional maturity. Often spanning across large areas, such formations may however experience spatial variability in burial and temperature exposure potentially leading to a heterogeneous diagenesis and subsequent reservoir quality. To assess such potential variability, this case study focusses on the diagenesis of the aeolian units of the Lower Jurassic Etjo Formation in Namibia, exposed at three key localities lying >100 km apart from each other. The Etjo Formation has experienced two major burial phases controlled by the emplacement of (I) Jurassic Karoo and (II) Lower Cretaceous Paraná-Etendeka volcanic rocks separated by an intervening exhumation phase. Petrographic analysis reveals very different rock properties between the localities with respect to intergranular volumes (IGV), intensity of quartz cementation, and preserved porosities. Average IGV and quartz cement values are 30.7 % and 24.3 % at Gamsberg, 23.7 % and 6.5 % at Waterberg and 19.7 % and 15.4 % at Mt. Etjo. Point-counted intergranular porosity values are on average 2.6 % (Gamsberg), 10.8 % (Waterberg), and 1.5 % (Mt. Etjo). Waterberg samples had an on average 72 % larger nucleation surface area available for quartz cement growth than samples from Mt. Etjo. The higher quartz cement volumes at Mt. Etjo therefore argue for a higher thermal exposure than at Waterberg. This is supported by kaolinite-to-illite transformation only occurring at Mt. Etjo. We attribute the higher temperature signature to the proximity of Mt. Etjo to the center of lower Cretaceous Paraná-Etendeka volcanism and related elevated thicknesses of the lava pile or heat flow increase. At Gamsberg, there is evidence for a quartz cement generation that formed during the Jurassic. This earlier cement stabilized the grain framework and preserved the IGV during the following Etendeka burial event. The Etjo Formation provides an exceptional example for the wide range of very low to very high degrees of compaction and cementation that can occur within an otherwise homogeneous, texturally and compositionally mature sandstone formation. This study underscores the importance of accounting spatial variations in burial depths and temperatures when predicting the diagenetic properties of reservoir rocks.

A Study on the Thermal Physical Property Changes in Formation Rocks during Rapid Preheating of SAGD

The incorporation and application of SAGD rapid preheating technology effectively solve the problem of the long preheating cycle in the SAGD steam cycle. The thermal properties of reservoir rocks are an important factor affecting the heat transfer law governing their formation during the rapid preheating process of SAGD. During the rapid preheating process of SAGD, the expansion of the reservoir and the steam cycle process will cause changes in the pore permeability, oil-water saturation, and temperature of the reservoir rocks, which will inevitably lead to differences in the changes that occur in the thermal properties of the reservoir rocks, compared to those under the influence of a single factor. In this study, experiments were conducted to determine the thermal properties of reservoir rocks under the combined influence of pore permeability, oil-water saturation, and temperature, quantitatively characterizing the changes in the thermal properties of reservoir rocks. Using the orthogonal method to design and carry out experiments for determining the thermal properties of reservoir rocks, the main factors affecting the thermal properties of reservoir rocks and the significance of each factor’s impact on the thermal properties of reservoir rocks were determined through intuitive analysis and variance analysis of the experimental results. Finally, a regression equation that can characterize changes in the thermal properties of reservoir rocks under the influence of multiple factors was obtained through multiple nonlinear regressions of the experimental results.

Appropriate characterization of reservoir properties and investigation of their effect on microbial enhanced oil recovery through simulated laboratory studies

Appropriate characterization of reservoir properties and investigation of the effect of these properties on microbial metabolism and oil recovery under simulated reservoir conditions can aid in development of a sustainable microbial enhanced oil recovery (MEOR) process. Our present study has unveiled the promising potential of the hyperthermophilic archaeon, identified as Thermococcus petroboostus sp. nov. 101C5, to positively influence the microenvironment within simulated oil reservoirs, by producing significant amounts of metabolites, such as biosurfactants, biopolymers, biomass, acids, solvents, gases. These MEOR desired metabolites were found to cause a series of desirable changes in the physicochemical properties of crude oil and reservoir rocks, thereby enhancing oil recovery. Furthermore, our study demonstrated that the microbial activity of 101C5 led to the mobilization of crude oil, consequently resulting in enhanced production rates and increased efficiency in simulated sand pack trials. 101C5 exhibited considerable potential as a versatile microorganism for MEOR applications across diverse reservoir conditions, mediating significant light as well as heavy oil recovery from Berea/carbonaceous nature of rock bearing intergranular/vugular/fracture porosity at extreme reservoir conditions characterized by high temperature (80–101 °C) and high pressure (700–1300 psi). Core flood study, which truly mimicked the reservoir conditions demonstrated 29.5% incremental oil recovery by 101C5 action from Berea sandstone at 900 psi and 96 °C, underscoring the potential of strain 101C5 for application in the depleted high temperature oil wells.

Numerical Simulation of Rock Vibration Response under Ultrasonic High-Frequency Vibration with High Confining Pressure

As deep oil and gas resources and Carbon Capture and Storage (CCS) are developed, enhancing drilling efficiency in hard rock formations has emerged as a critical technology in oil and gas extraction. The advancement of ultrasonic, high-frequency vibration rock-breaking technology significantly facilitates efficient rock crushing. When subjected to ultrasonic high-frequency vibrations, the rock’s response is a crucial issue in implementing ultrasonic vibration rock crushing technology. This study employed numerical simulation and theoretical deduction methods, utilizing a multi-physics approach that couples solid mechanics with pressure acoustics. It integrated information on common influencing parameters of ultrasonic generators and reservoir rock properties to establish model parameters, analyze simulation results, and perform theoretical deductions. The research investigated the response patterns of different-sized rock samples under high-frequency ultrasound vibration excitation across various frequencies, amplitudes, and confining pressure conditions. Through the development of a three-dimensional model and the application of principles from solid mechanics and elastoplasticity, the study derived equations that describe the resonance frequencies of rock blocks under confining pressure as functions of relevant rock parameters. The findings indicate that ultrasonic vibrations can effectively induce rock displacement. Under excitation frequency sources, the rock exhibits a natural frequency correlated with the rock sample size. When the excitation frequency approximates the natural frequency, the rock resonates. At this point, the rock’s surface displacement is maximal. The rock undergoes tensile stress, leading to stress concentration that facilitates rock damage and fragmentation. Increasing the excitation amplitude enhances rock crushing, as it amplifies the maximum surface displacement under the same frequency excitation. Confining pressure exerts an inhibitory effect on the rock’s vibration response, but it does not alter the resonance frequency of the rock sample, a fact verified by both numerical simulation and theoretical results. Based on the research findings in this paper, it can help to optimize the parameters of ultrasonic vibration rock breaking in field application to achieve the best rock-breaking effect.

The Early Determination Method of Reservoir Drive of Oil Deposits Based on Jamalbayli Indexes

Summary Historically, the concept of “reservoir drive” aimed to simplify the mathematical modeling in reservoir engineering. Within this framework, the energy of the reservoir, particularly its aquifer, was idealized, leading to classifications such as “partial waterdrive,” “full waterdrive,” “gas cap drive,” and so forth. However, in reality, all existing energy sources interact simultaneously within reservoirs. Accordingly, this study aims to develop a new concept for a more realistic description of reservoir drive mechanisms and evaluation of reservoir energy performance. Numerous computer simulations have revealed a strong correlation between the ratio of relative changes in pore volume to relative changes in reservoir pressure and the reservoir’s energy nature and activity level. Moreover, the noted ratio did not depend on production technology, pressure/volume/temperature properties of hydrocarbon systems, rheological properties of reservoir rocks, or other factors. Based on this correlation, specific parameters termed as Jamalbayli Indexes (JI) have been identified to quantitatively describe reservoir energetic performance. JI consist of two parameters. One of them describes the relative change in pore volume per unit of relative change in reservoir pressure, and the second is the relative change in pore volume per unit of relative change in formation porosity. Here, “relative change” means a change in a parameter relative to its original value. These parameters are dimensionless and can have values around or equal to unity. A new conceptual framework for describing reservoir drive mechanisms based on JI has been formulated. According to this framework, reservoir drive mechanism is determined by comparing the computed JI values with unity rather than relying on subjective assessments of the trend of some functional dependencies. For the first time, it has become possible to express the reservoir drive performance quantitatively and determine the level of energy activity of the reservoirs with the help of JI. Additionally, a technique has been developed to evaluate the numerical values of JI for specific oil (including volatile oil) deposits based on the production data at any stage of production. The proposed methodology was tested using data from the eighth horizon of the Russkiy Khutor field in Russia. The test results not only confirmed the reliability of the obtained model but also demonstrated the adequacy of the proposed concept as a whole. Summarizing the results of other works by the authors, the adequacy of the proposed concept for both oil, gas, and gas condensate deposits has been confirmed. The research findings are expected to contribute to updating the traditional principles used for the mathematical problem statements in fluid flow in porous formations. Additional Key Terms and Phrases Reservoir Drive Mechanism; Early Determination Methods; Reservoir Performance Analysis; Production Data Interpretation; Enhanced Oil Recovery; Reservoir Management; Drive Mechanism Identification; Reservoir Fluid Dynamics; Production Rate Analysis; Reservoir Engineering Techniques; Field Development Planning; Reservoir Simulation; Pressure/Volume/Temperature (PVT) Analysis; Production Monitoring and Evaluation drive mechanisms; production data analysis; volatile oil; Jamalbayli indexes; drive performance indexes

Optimized artificial neural network application for estimating oil recovery factor of solution gas drive sandstone reservoirs

The most crucial aspect in determining field development plans is the oil recovery factor (RF). However, RF has a complex relationship with the reservoir rock and fluid properties. The application of artificial neural networks is able to produce complex correlations between reservoir parameters that affect the recovery factor. This research provides a new approach to improve the accuracy of the ANN model in the form of steps including removing outlier data, selecting input parameters, selecting transferring functions, selecting the number of neurons, and determining hidden layers. By applying these steps, an ANN model was selected with nine input parameters consisting of oil viscosity, water saturation, initial oil formation volume factor, formation thickness, initial pressure, permeability, specific gravity of oil, porosity, and original oil in place. Furthermore, based on the correlation coefficient, a tangent sigmoid transferring function, 30 neurons, and two hidden layers were determined. The proposed ANN correlation gives the best accuracy compared to the previous correlations. This is proved by the highest correlation coefficient of 0.91657.

GeosPIn: A MATLAB library for geostatistical petrophysical inversion

The petrophysical inversion of seismic data is one of the key components of seismic reservoir characterization. The goal of petrophysical inversion is to estimate the petrophysical properties of reservoir rocks, such as porosity, volumes of minerals or lithologies, and water and hydrocarbon saturations, from seismic data. This process can be performed by combining seismic amplitude-variation-with-offset (AVO) modeling and rock-physics relations with deterministic or probabilistic inverse theory methods, either in a two-step approach based on seismic AVO inversion and rock-physics inverse mapping or in a single-loop step that includes both. We present a comprehensive MATLAB library named Geostatistical Petrophysical Inversion. The novelty of the library lies in a single-loop geostatistical inversion method based on probability field simulation and ensemble smoother multiple data assimilation, as well as its implementation for applications to 3D data sets. The library also includes a Bayesian petrophysical inversion based on the two-step approach for comparison. We illustrate the main algorithms, explain the structure of the source codes, and demonstrate the library applications through 1D and 3D examples.

Machine Learning Assisted Prediction of Porosity and Related Properties Using Digital Rock Images.

Accurately estimating reservoir rock properties is paramount for modeling the storage and flow of fluids (hydrocarbon, carbon dioxide, and groundwater) in porous media. However, existing laboratory techniques to measure rock properties are usually time-consuming, expensive, and computationally intensive. This work proposes an efficient workflow that uses the machine learning algorithm, based on the convolutional neural network (CNN) framework, to predict rock properties from microcomputed tomography (micro-CT) X-ray images. The workflow involves data preprocessing, label extraction, training, and prediction using the segmented images of the rock to predict porosity, throat area, and pore surface area, which are essential for pore-scale modeling. The model was trained and validated on the Bentheimer sandstone, which was then used to predict properties of other sandstones (Castlegate and Leopard) with different pore structures and flow properties. The model yielded a good prediction for the throat and pore surface area but a significant error for porosity. Subsequently, a new complex model was trained and validated using diverse images from Bentheimer and an additional rock Castlegate, which was then used to predict the properties of Leopard sandstone. The new model improved the prediction of each property, resulting in mean absolute percentage error (MAPE) values of 2.19%, 3.04%, and 6.08% for porosity, pore surface area, and throat area with the binary images, respectively. In addition, we present a novel data-driven method using a simple regression model to predict the absolute permeability of a digital rock sample using the pore network parameters as predictors. The extreme gradient boost (XGBoost), which performed the best among several machine algorithms, was trained and validated using digital rock images from Bentheimer and Castlegate sandstone. The generated model was then used to predict the absolute permeability of the Leopard sandstone with an R 2 of 0.813, which was a significant improvement over the model generated solely by using either the Bentheimer or the Castlegate sandstone images. Furthermore, our analysis showed that the tortuosity had the most significant effect on the absolute permeability prediction of the rock sample. This study showed that we can reliably predict the morphological properties of porous media using computationally efficient models generated from digital rock images, which can be used to build a regression model to predict the crucial petrophysical properties needed to model the flow of fluids in porous media.

Beetaloo gas, hydrogen and geothermal resources – insights from 3D basin modelling

The Beetaloo Sub-basin hosts a large proven shale gas resource, and this study demonstrates the opportunities for other low-emission energy sources including geothermal energy and natural hydrogen. CSIRO has developed a 3D basin model that predicts reservoir rock properties, pore pressure, composition of hydrocarbons and gas capacity of the Velkerri and Kyalla shales. Kinetic modelling also demonstrates that where Velkerri shale is overmature for hydrocarbons it potentially generated significant amounts of free molecular hydrogen. However, the proportion of this hydrogen currently preserved in the basin is unknown. The model also reveals considerable temperature anomalies around specific structural domains with heat flow up to 100 mW/m−2, and these are likely associated with radiogenic basement lithologies. These thermal domains are targets to further investigate geothermal and natural hydrogen resource potential in the Beetaloo Sub-basin.

Fundamental principles and results of deep well lining

The review of the theory and practice of the special technological fluids application is analyzed. On the example of a specific borehole, with an actual vertical depth of 3287 m, intended for opening horizons B-17v, B-17n and project B-21, measures to clarify the filtration and capacity properties of reservoir rocks, increase production volumes are considered of hydrocarbons and accelerating the rate of selection of mining reserves. Testing in the interval 3364 - 3337.6 m of the B-21 horizon by using a set of test tools KVI-95, objectively proved that the specified object is characterized as penetrating, gas-saturated, the activity of which is reduced by contamination of the near-outbreak zone of the seam. As a method of determining clogging, a cut of the working end of the core with a length of 1 mm was applied. According to the results of the interpretation of the materials of the geophysical research of the specified borehole, it was established that the seam fluid comes from the interval 3339 - 3344 m. The paper determined that a promising way to solve the issue of high-quality cementing is the application of composite tamponage systems in combination with advanced preparation methods of borehole shaft.

Multifunctional-Team Approach Achieves Extended-Reach Record Offshore Abu Dhabi

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 216326, “Longest Extended-Reach-Drilling Well Worldwide Drilled in Middle East, Offshore Abu Dhabi, UAE,” by Marah Mohamad Alabed, Naser Salah Alsuwaidi, and Jamie Scott Duguid, SPE, ADNOC, et al. The paper has not been peer reviewed. _ The complete paper describes the engineering design and operational practices that supported the setting of a new extended-reach world record in a mature carbonate field offshore Abu Dhabi. This accomplishment reduces the carbon footprint of the development, allows acquisition of reservoir data earlier in the development plan, and accelerates production while reducing costs. This extended-reach development program is a strong example of what can be accomplished when a multifunctional team cultivates a strategic plan to expand technical and operational capabilities in a drilling campaign. Reservoir and Development-Plan Background The 1-md oil reservoir is a carbonate dominated by packstone and grainstone rock types in terms of storage capacity. Average porosity is 18%, and thickness is 130 ft. Permeability reduces in an southeast/northwest direction, dropping below 1 md. Calcite cementation development has occurred in the westernmost areas of the reservoir because of late oil in these low structural areas. Initially, the target reservoir was drilled at 2-km well spacing with a five-spot waterflooding scheme from wellhead platform towers. Later, development was optimized by a line waterflooding scheme at 250-m well spacing by development from an environmental island. The target reservoir area was partitioned into four development areas (West A, West B, West C, and West D). The partition is based on drilling reachability from environmental islands and underlying geology. The current optimized development began in the West A reservoir area through an artificially constructed island. The remaining reservoir areas required investment of two new islands. High risk is associated with these investment decisions because these reservoir areas degrade in terms of reservoir rock properties. Additionally, an increasing trend of water saturation exists with progress in the northwest direction within the transition zone. The development plan in the West A area is based on drilling segments called AB and BC, first with over-20,000-ft laterals to achieve production buildup by target date. To test the West B area, Segment BC was extended, thus covering both West A and B areas. This option reduced drilling complexity and maximized the reservoir-production rate. Additionally, by adopting the island drilling option instead of appraising a limited area of West B, an extensive area of approximately 10 km could be appraised. To implement this option, a stepout drilling plan was executed by drilling eight extended-reach maximum-reservoir-contact wells in increments to meet the goal of appraising the West B reservoir area. These first wells were extended in increments of 1,000–2,000 ft to test the capability to drill and run completion to target a measured depth (MD) of 45,000 ft. Upon applying learnings from these pilot wells, a stepout to extending wells to 50,000 ft MD and greater was studied. Fig. 1 shows the map of the subject drilled well with an extended MD of 50,000 ft with an underlying oil-saturation map. This optimized field-development strategy has allowed for effective West B reservoir appraisal.

Volcanic lithofacies control the space in unconventional, rhyolitic hydrocarbon reservoirs: The Hailar Basin, NE China

Volcanic rocks are generally characterized by significant spatial variations of lithofacies. The characterization of volcanic lithofacies is an important tool to achieve accurate reservoir prediction during hydrocarbon exploration because of the type of lithofacies strictly controls the porosity and other physical and chemical properties of reservoir rocks. Studying the lithofacies of rhyolitic volcanic rocks is essential for uncovering the genesis and characteristics of volcanic reservoirs. The Lower Cretaceous Shangkuli Formation is located on the western boundary of the Hailar Basin in NE China. This basin hosts oil-bearing rhyolitic volcanic rocks and represents a natural laboratory for investigating the spatial distribution of different lithologies and volcanic lithofacies. Here, we present detailed field observations, TESCAN Integrated Mineral Analysis (TIMA), and fluorescence imaging to characterize seven types of rhyolitic volcanic rocks belonging to four main lithofacies associations. We examine the relationship between lithofacies associations and reservoir rocks. Field observations reveal the existence of volcanic conduit, pyroclastic, effusive, and extrusive lithofacies associations within the Hailar Basin. These lithofacies associations can be further subdivided into nine distinct subfacies. Among these, the extrusive lithofacies association is dominant and it is followed by pyroclastic, effusive, and volcanic conduit lithofacies associations. Intra-spherulite microfractures and pores, lithophysa cavities in the extrusive lithofacies associations, and inter-clast pores of the volcanic conduit lithofacies associations constitute the primary reservoir spaces of rhyolitic reservoirs. The lithofacies associations exert a control on the reservoir spaces of rhyolitic volcanic rocks by limiting the degree of supercooling (ΔT) and volatile content, which impact the formation of different textures in rhyolitic magma during syn-eruptive processes. We conclude that spherulitic and lithophysa rhyolites in the extrusive lithofacies associations, and the crypto-explosive breccias in the volcanic conduit lithofacies associations are promising targets for oil and gas exploration. The facies model we obtain from the Hailar Basin may be extended to similar rhyolitic rocks in other basins hosting unconventional reservoirs.

Reservoir Prediction and Prospectivity of Omos Field Onshore Niger Delta Basin, Nigeria

Reservoir prediction and prospectivity are performance indices of the oil and gas field development planning and reserves estimation which depicts the behaviour of the reservoir in the future; its success is dependent on accurate description of the reservoir rock properties, fluid properties, rock-fluid properties and flow. Hence, the objective of this paper was to investigate and predict the reservoir and prospectivity of Omos Field, Onshore Niger Delta Basin, by integrating appropriate standard methods. Results obtained from rock physics attribute map analysis revealed very high Mu-Rho values between 13.0-16.2 Gpa, that is expected for sand presence, and this agrees with the good quality reservoir sands predicted from sequence stratigraphy study.Lambda-Rho values obtained ranges between - 1 to 9.5 GPa, with a much lower value between -1 to 4.3 in the prospective zone that indicates the presence of hydrocarbon bearing sand. These results agree with the results of structural and amplitude maps analysis. Hence the prospective reservoir has a very good hydrocarbon potential in this zone and should be a target for further appraisal for development and production purposes.