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Multi-fractured horizontal wells have been an admirable completion technique for unconventional resources such as in Tuscaloosa Marine shale (TMS) and Eagle Ford Shale (EFS) plays located in the United States. Studies have shown that the productivity of multi-fractured wells of these two shale plays are majorly based on the fracture conductivity, which may be dependent on the type of the geometrical shape of the fractures connecting the fluid to the well. A reliable model is desirable to the operator to accurately capture the productivity of multi-fractured shale wells. Several mathematical models have been adopted with various assumptions that include simple slot geometry for fracture shape in the derivation of production rate models. These assumptions significantly simplify the existing model's applications but limit the efficiency of the models to accurately predict the fluid production rate. Failure to utilize an elliptical fracture shape and a correct drive mechanism-based model for analyzing flow rate have been considered as a vital reason for the disparity between the calculated results by the past investigators and the exact values obtained from TMS and EFS field measurements. In this study, an elliptical model based on the fracture geometry has been derived to analyze the productivity of multi-fractured shale wells considering the accurate drive mechanism for the shale play. The model validation has been achieved using field data from the Tuscaloosa Marine shale (TMS) and the Eagle Ford Shale (EFS) plays. The results generated from the newly improved model resulted in more accurate outcomes when compared with results presented by Yang and Guo (2019) and Guo and Schechter (1997); all these authors assumed the cross-sectional area of the induced fractures as being a slot showed nonconformity using real life values from the Tuscaloosa Marine shale (TMS) and the Eagle Ford Shale (EFS) plays as benchmarks. The newly improved model reduces the prediction percentage error to 0.55% and 0.43% compared to the percentage error reported by Yang and Guo (2019) as 9.1% and 3.5% and by Guo and Schechter (1997) respectively as 29.7% and 47.2 % using the actual oilfield results as their benchmark. The accurate prediction of the long-term productivity of multi-fractured oil shale depends on the ability to determine fracture geometry and the drive mechanisms that dominantly control flow in the shale play considered. Sample calculations of flow rate of the two fields considered and the controllable parameters influencing the flow rate have also been identified. The study would serve as a tool for accurate assessment of flow rate in multi-fractured wells of shale plays and analyzes its performance.

With the development of high-pressure and high-temperature condensate gas wells, the wellbore blockage problems have become increasingly serious. Hence, selecting appropriate treatment technology plays a crucial role in solving the wellbore blockage problems. This study presents a comprehensive literature review on understanding the blockage type, mechanism, and treatment of the high-temperature and high-pressure condensate gas wells. The causes, endangerments, mechanisms, influences, and preventive technologies of the 4 wellbore blockage types are presented. The significant aspects of the treatment technology, such as the principle, type, advantage and disadvantage, adaptability, limitation, and future research direction of the treatment technologies, are thoroughly discussed. The breakthrough solid autogenetic heat treatment technology has been selected to remove hydrate blockage. The present review highlights the current state in the industry, future position, and strategies for the researchers to follow. Finally, the advantages and disadvantages and future research directions of specific treatment technology are presented on the removing effect, cost, and environmental aspects.

The log response of thin oil layers is greatly subject to environmental factors such as shoulder beds, resulting in errors high enough to influence the appraisal of rock lithology and fluid properties and increasing the difficulty of interpretation of logging curves and the effective evaluation of thinly laminated sand. The development of high-resolution logging instruments and logging curve processing technology improves the resolution and accuracy of logs, but with some limitations. So far, the geometric factor theory has been an effective approximate approach for induction logging correction. Based on the working principle of the induction/resistivity log and on previous studies, we have developed a new model to correct the resistivity log response of thin layers by taking advantage of the geometric factor. This method can improve the accuracy of the resistivity log for the calculation of porosity and water saturation. Our case study indicates that more reliable resistivity can be acquired to better characterize thin layers.

The concurrent transport of hydrocarbon, water, and most times solids ensues all through the production system concerned in transporting multiphase fluid from the producing reservoir zone to the wellbore and then to surface. The flow capacity of a well can be estimated through the inflow performance relationship (IPR) that essentially depends on productivity index (PI). Productivity index is a vital and indispensable oil and gas industry tool for forecasting the deliverability and helps in economic feasibility studies of the well. The lack of a correct model for bottom-hole flowing pressure calculation has always been a challenge and results in erroneous estimate of productivity index of a production well. Numerous models on bottom-hole flowing pressure in wells have been recounted in different literatures over the years. Many of the earlier works were based on steady-state flow assumption, likewise not all the constituent terms that practically influence flow behavior of fluid in pipe were considered in derivation of the past models. In the present work, an enhanced semi-analytical model for determining well bottom-hole flowing pressure is offered where all the constituent terms practically influence flow behavior of fluid in pipe and employed in building the new model for estimating productivity index in a vertical well. This article builds a semi-analytical model for predicting flowing pressure at every flow transition period evidencing the water hammer pressure fluctuations often experienced at the start-up operation. Subsequently, the time-dependent flowing pressure obtained from the newly derived model was used to estimate the productivity index using high gas-oil ratio surface data from Niger Delta field. The result of productivity index obtained at steady-state period shows that the average prediction percentage error of the current approach is reduced to 3.78% compared to previously derived steady-state-based model by Guo et al. (2007, “A Rigorous Composite-IPR Model for Multilateral Wells,” Society of Petroleum Engineers, SPE 100923, San Antonio, TX, p. 11), Guo (2001, “Use of Wellhead-Pressure Data to Establish Well-Inflow Performance Relationship,” SPE Eastern Regional Meeting, Canton, OH, Oct., SPE 72372, p. 7), and Adesina et al. (2018, “A Realistic Model for Estimating Productivity Index of Vertical Well Using Wellhead Data,” Society of Petroleum Engineers, SPE-193506-MS) that, respectively, report as 18.59%, 5.23%, and 3.96%. The factors that influence the magnitude of water hammer pressure fluctuation at the start-up period have been identified through the derivation. The semi-analytical model improves the prediction accuracy and aids the reliability of design to avoid incidence of pipe burst due to pressure peak and serves as a tool to analyze the well performance.

The limitation in the formulation and application of synthetic surfactants in petroleum industry is owing to their high cost of production or importation and their associated toxic effect which have been proven to be harmful to the environment. Hence it is vitally imperative to develop an optimum surfactant that is cost-effective, environmentally safe (biodegradable) and equally serves as surface acting agent. This study discusses the production of microbial produced bio-surfactant and its application in enhanced oil recovery. The bacteria Pseudomonas sp. were isolated from urine and allow to feed on neem seed oil as the major carbon source and energy. The crude bio-surfactant produced from the fermentation process was used to prepare three (3) solutions of bio-surfactants at different concentrations of 5 g/500 mL, 10 g/500 mL and 15 g/500 mL, and their suitability for enhanced oil recovery (EOR) was evaluated. Reservoir core samples and crude oil collected from the Niger Delta field were used to evaluate the EOR application of the microbial-derived surfactants. The sets of experimental samples were carried out using core flooding and permeability tester equipment, and the results obtained were compared with conventional waterflooding experiments. The three bio-surfactant concentrations were observed to recover more oil than the conventional waterflooding method for the two core samples used. Optimum performance of the produced microbial-derived surfactant on oil recovery based on the concentrations was observed to be 10 g/500 mL for the two samples used in this study. Therefore, eco-friendly bio-surfactant produced from neem seed oil using Pseudomonas sp. has shown to be a promising potential substance for enhanced oil recovery applications by incremental recoveries of 51.9%, 53.2%, and 29.5% at the concentration of 5, 10, and 15 g/500 mL and 24.7%, 28.7%, and 20.1% at concentration of 5, 10, and 15 g/500 mL for the two core samples, respectively.

Pressure transverse in foam drilling operation is sensitive and difficult to predict particular at the start of flow that follows the unavoidable shut in due to inevitable procedure of stop and proceed arising from re-connection of additional drilling pipe to further drill depth. The practice in drilling may not enable the flow to attain steadiness flow region before running in the length of drill pipe. Most existing models in the literature for predicting pressure transverse in foam drilling operation only captured the steadiness flow region of the foam drilling operation by keeping out restriction terms induced by accumulation and kinetic for simplicity sake, hence unsteadiness flow region experienced during foam drilling operation was rarely modelled. It is highly expedient to derive a model that evident the unsteadiness region in order to accurately predict pressure transverse, hence sufficiently analyses the well stability during foam drilling operation.In this study, a model for forecasting pressure transverse in foam drilling operation was established considering restriction term caused by accumulation and kinetic that constitute for accurate formulation of hydraulic model that govern flow of foam during underbalanced drilling. By applying the proposed model to a case study reported in literature, pressure transverse at unsteadiness flow region for foam drilling operation can be quantitatively estimated and analyzed. The result obtained in a case study carried out indicates high variance in pressure as function time at the beginning of flow in foam drilling where unsteadiness is promoted before matching up closely with the results obtained from the existing Guo et al 2003 model at the steadiness flow region. The new model has a better accuracy with a percentage error of 0.74% and 6.4% as compared to previous models by Guo et al 2003. The proposed model make possible for drilling engineer to take decision with larger precision during hydraulic design of foam drilling operation and guaranteeing well stability in complex drilling system.

For unconventional reservoirs, water flooding performs poorly because of low displacement efficiency; gas flooding shows limited enhanced oil recovery (EOR) capability due to gas breakthrough. Carbonated water injection (CWI) and active CWI (ACWI) are promising EOR methods which combine advantages of water and gas flooding. This paper provides experimental and numerical studies of carbonated water and surfactant injection based on a case study in Changqing Oilfield, China, which is the first time to investigate the feasibility of CWI and ACWI for tight oil reservoirs. This study compares performances of active water injection (AWI), CWI, Water altering gas (WAG), and ACWI. Experimental results reveal that the oil recovery of CWI is 2.7% more than WAG. ACWI achieves the highest incremental oil recovery (9.43%) among four methods. The sensitivity analyses of ACWI + WAG is further implemented experimentally, which demonstrates that ACW as a pre-flood improves 7% of oil recovery during WAG process. For Changqing tight reservoir cores, the optimal injection volume of ACW is 0.8 pore volume. Numerical simulations are conducted to validate the capability of cubic Equation-of-State coupled with Henry's law (EOS/H model) for CWI in tight oil reservoirs, indicating EOS/H model is applicable to correlate phase behavior of carbonated water and oil system. This paper, for the first time, investigates the EOR performance of ACWI in tight oil reservoirs. These results explore the feasible application of using CWI/ACWI in tight oil reservoir development.

The acid-fracturing is applied wildly to simulate the formation in vuggy carbonate reservoirs. But it does not figure out clearly the mechanism of fracture propagation while fracture encountering dissolved cavern, and there are few researches considering the influence of dissolved cavern on fracture propagation. In order to study fracture propagation regularity in vuggy carbonate reservoirs, numerical simulations are carried out by the seepage–stress–damage coupling equation based on the damage mechanics theory and the accuracy of the model is validated by comparison with experimental results. Some factors influencing the fracture propagation such as dissolved cavern, formation parameters, and construction parameters are considered. The simulation results show that there are four fracture propagation forms after the fracture encountering dissolved cavern, namely, block, crossing over directly, crossing over after deflection, and deflection. The entire process of injecting the pressure curve can be divided into five stages: initial initiation zone, encountering dissolved cavern pressure released zone, the dissolved cavern inside builds the pressure zone, re-ruptured zone, and fracture propagation zone. The horizontal principal stress difference of the formation controls the tendency of fracture propagation and the generation of branch fractures. It is easy to generate branch fractures under the condition of low horizontal principal stress. The increase in horizontal principal stress limits the deformation of fracture, making it more convenient for fracture to extend toward the maximum horizontal principal stress. The study results are significant for optimizing fracturing construction plans and improving the probability of connection between fracture and dissolved cavern.

Temporary plugging fracturing is an effective way to enhance the fracture complexity and increase the stimulated reservoir volume (SRV) of unconventional reservoirs. The performance of temporary plugging agents (TPA) directly affects the success rate of temporary plugging. Currently, laboratory evaluation of the plugging effects of the TPA is rarely reported, and there are no industrial standards on laboratory evaluation of TPA plugging. In this study, two new experimental methods were used to evaluate a novel particulate TPA. The plugging performance of the TPA to the core end face and the propped fractures was measured through displacement experiments of cores, and the applicability of its basic performance to the temporary plugging fracturing was verified. Furthermore, the large-scale true triaxial simulation experiment of temporary plugging fracturing was carried out to confirm the influence mechanism of different factors on fracture propagation during temporary plugging. Finally, the influence rule of different types of combinations of TPA and placement patterns on the plugging was obtained based on laboratory evaluation of the conductivity. The results show that the novel TPA causes effective temporary plugging on the core end face and the propped fractures and has the strong plugging performance, and the TPA solubility in the carrying fluids decreases with the increase in the TPA concentration. The basic performance of the TPA meets the requirements of temporary plugging fracturing. If the proppants and 20% fibers are placed within the fracture in the mixed pattern, the fracture is initiated along the direction of the horizontal maximum principal stress. The preset fracture reduces the fracture initiation pressure. The fracture complexity is closely related to the placement pattern of TPA and proppants. If the preset fractures are filled by the uniform mixture or the plug of the 20/40 mesh or 20/80 mesh particulate TPA (4%), fibers (1%), and proppants, the fracture initiation pressure significantly increases, and the complex fractures are formed after fracturing. Effective plugging cannot be formed only by mixing the fibers with the proppants, and the uniform mixture of the proppants and 4% particulate TPA and the 6% particulate TPA at the front end of the fracture form a temporary plugging belt, achieving effective plugging. The fibers improve the conductivity under the low closure stress, and it has a certain effect of temporary plugging under the closure stress above 30 MPa. The research results provide the design consideration for creating the complex fracture by temporary plugging.

Although the problems of wax deposition in multiphase transportation pipelines have been addressed and wax deposition models have been developed in recent years, the complex wax deposition paths derived from the potential variety of flow regimes in multiphase flow have not been well understood. This study presented a method for characterizing wax crystals aggregation and developed a model for describing the wax deposition path in oil−water two-phase flows. The effect of the emulsified water droplets on wax crystals aggregation in shearing flows was identified using the polarized light microscopy and image analysis method. The role of the emulsified water droplets in the wax deposition path reaching the upper side and lower side of the pipeline wall was discussed by solving the developed model which involves the possible inclination angle of the multiphase transportation pipeline. The availability of the mechanistic model was validated by the data and knowledge in the existing literature. The results indicated that the circular degree and particle size of wax crystals showed a characteristic that it first increased and then decreased with the accumulation of emulsified water droplets in shearing flow, and this transition appeared to the phase inversion point of the oil−water two-phase. The wax deposition path was complex in multiphase transportation. The velocity for wax crystals depositing to the pipeline wall decreased, and the time for wax crystals depositing to the pipeline wall extended with the existence of emulsified water droplets. This behavior became remarkable when the dispersion stability of the oil−water two-phase enhanced.

Gaining a better understanding and measuring unconventional well complexity are vital to developing an oil and gas field successfully. However, there is a lack of quantitative assessment framework for evaluating unconventional wells. This paper created an index evaluation system to assess unconventional well readiness for development, which considers the various well characteristics. The unconventional well complexity index is calculated using five major level-1 elements, and the weight of each sub-element was calculated using the factor analysis statistical method. The well evaluation system was applied to evaluate 20 unconventional well programs for their readiness for development; the evaluation results were analyzed in terms of well complexity distribution and the relationship between unconventional well complexity and duration performance. Recommendations for dealing with various unconventional well complexity were also proposed. The evaluation framework was also verified to be an efficient method for assessing unconventional well development readiness.

Retrieving standard sized core plugs to perform conventional geomechanical testing on organic rich shale samples can be very challenging. This is due to unavailability of inch-size core plugs or difficulties in the coring process. In order to overcome these issues, statistical grid nanoindentation method was applied to analyze mechanical properties of the Bakken. Then the Mori-Tanaka scheme was carried out to homogenize the elastic properties of the samples and upscale the nanoindentation data to the macroscale. To verify these procedures, the results were compared with unconfined compression test data. The results showed that the surveyed surface which was 300 μm ×300 μm is larger than the representative elementary area (REA) and can be used safely as the nanoindentation grid area. Three different mechanical phases and the corresponding percentages can be derived from the grid nanoindentation through deconvolution of the data. It was found that the mechanical phase which has the smallest mean Young's modulus represents soft materials (mainly clay and organic matter) while the mechanical phases with the largest mean Young's modulus denote hard minerals. The mechanical properties (Young's modulus and hardness) of the samples in X-1 direction (perpendicular to the bedding line) was measured smaller than X-3 direction (parallel to the bedding line) which reflected mechanical anisotropy. The discrepancy between the macromechanical modulus from the homogenization and unconfined compression test was less than 15% which was acceptable. Finally, we showed that homogenization provides more accurate upscaling results compared to the common averaging method.

The lamellation fractures in marine shales are important to the accumulation and preservation of shale gas, whose characteristics and controlling factors are still unclear. This paper focus on the characteristics descriptions and controlling factor analyses based on core observations, thin sections, and scanning electron microscope (SEM) experiments. The marine shales of Paleozoic Wufeng Formation and Longmaxi Formation in the Fuling Area of Eastern Sichuan Basin are taken as an instance. The lamellation fractures are occurring along the direction of the lamellations, partially of them curved, bifurcated, and converged. The apertures of fractures typically range from 1 to 500 μm. Only a few (

With the increasing demand of precisive reservoir characterization in exploration and development of oil and gas, wettability plays a more and more significant role because it influences oil and water distribution. The determination of wettability has been a challenge to the researchers focusing on this area. In this study, a new method is proposed for the determination of wettability based on resistivity index prediction. Firstly, the model for estimating resistivity index using capillary pressure, porosity and median pressure by J-function is derived. Secondly, the model to estimate resistivity index via T2 time, porosity and T2 geometric mean is derived, which combines J-function with Schlumberger-Doll-Research (SDR) model. Thirdly, a new parameter, the ratio of mean saturation index calculated from first method to the one calculated from second method, is used to determine the reservoir wettability. To calibrate and verify the established models, 30 cores were acquired for the petrophysical experiments. The experimental results of 25 cores are used to calibrate the established models and build the quantitative relationship between the wettability and the ratio of mean saturation index, with a relevance of 0.96. Besides, the calibrated model is tested by using the experiment data of the rest 5 cores. The estimated wettability conforms to the experimental results. Finally, the processing and interpreting results of log data also indicate that the proposed model for quantitative prediction of wettability features good application effect. In conclusion, the proposed method for quantitative prediction of wettability is effective and highly reliable, which solves a difficult problem in formation evaluation.

The pipeline is an efficient tool to transmit fluid in a long distance. However, due to different reasons such as pipe aging or natural disaster, multiple leaks can occur to the broken pipeline system. Therefore, it is very crucial to find an accurate, quick, and low-cost method to detect the leakages in the pipeline. In this study, pressure distribution analysis was proposed to diagnose the location of the leakages via experimental study and Computational Fluid Dynamics (CFD) simulation. Different dimensionless variables, which are the dimensionless leak location, dimensionless leak rate, and dimensionless pressure drop, were applied in our analysis. Through the mathematical modeling which was built on the dimensionless variables, the locations of the leakages can be detected. Multiple flowrate testing was conducted to detect the locations of two leakages. The proposed method can be used to monitor the severity of the pipeline during the operation. Different from former researchers, our work combined the experimental study, CFD simulation, and dimensionless variable analysis to solve the problem of two-point leak detection. This new method can be applied to detect the leakages under different flow rates. For the detection of multiple leaks, a trial-and-error approach was investigated. When the pressure and flow rate at the inlet and outlet of the leaking pipe are known, not only does the method supply an inexpensive way to identify the leaks but also it shortens the time interval between an accident occurring and finding the leak points.

Natural gas is a clean fossil energy and an important sector in the energy consumption chart. Because of its reliability and low carbon-hydrogen ratio, the demand for natural gas increases steadily to replace coal and wood to better protect environment. To accommodate the ever rising in natural gas production and transportation, more gas pipelines are being constructed. Meanwhile, the existing gas pipelines are aging inevitably. One of the critical needs in natural gas flow assurance is detecting and locating pipeline leak in a timely manner. A reliable and timely detection of the leakage of gas pipeline can not only reduce the loss of hydrocarbon, but also limit the damage to facilities, possible loss of life, and the extent of environmental pollution. Two or more leakage points in a pipeline were observed in the field. Physical methods and mathematical models were employed to detect pipeline leakages. However, literature review indicates that no mathematical model has been developed to detect multiple leaks in the same pipeline. This study focused on the detection of two leak points in a pipeline. Multi-flowrate tests are proposed to evaluate the locations and sizes of leakages in two leak points. The new mathematical model is crucial when no physical inspection is available. The proposed model can be used to monitor possible leak in real-time because flowrate and pressure that are utilized to estimate multiple leaks are monitored in real-time and are available almost simultaneously. Therefore, the new method provides a practical, quick, and low computational cost approach to detect multiple leakages. The proposed method is important because existing mathematical models assumed single leak in a pipeline, which limits their applications because the detection will be misleading if there is more than one leakage in the same pipeline. The proposed model can differentiate single-leakage scenario from multi-leakage scenario based on multi-rate tests. The identification is critical because it guides the leakage detection to the right direction.

Accurately measuring and understanding reservoirs is critical for ensuring successful reservoir development, but there is a lack of quantitative and comprehensive evaluation systems available for assessing reservoirs for development purposes. This study developed a quantitative evaluation system to measure oil and gas reservoir readiness for development, considering the reservoir and input data quality. The reservoir quality index is determined using five major elements with the input data quality determined by the quality of six data sources. The weight of each element was determined using the principal component analysis method. The newly developed evaluation system was used to assess the development readiness of 20 reservoirs; the results of the reservoir application were analyzed in terms of the reservoir quality index and data quality index. Recommendations for dealing with reservoir developments with different evaluation results were also proposed. The evaluation system developed proved to be an effective method for evaluating reservoir development readiness based on the results of applications and feedback.

Historical records on the performances of global offshore oil and gas (OG therefore, there is a significant need to provide an effective evaluation system for offshore O&G projects to identify project deficiencies and improve project performance. Considering their unique characteristics, a set of two-dimensional industry metrics were developed to evaluate offshore O&G projects across five categories: cost, schedule, safety, production, and quantity. The project data and the results of a survey taken by industry experts were used to validate the credibility of the metrics. In addition, the drivers of each metric are discussed or verified with first principle and were confirmed by industry experts. Finally, the practice for using these metrics is recommended. In other words, with the characteristics of offshore O&G projects taken into account, these metrics will be verified so they are perceived as an efficient tool to evaluate project competitiveness and identify gaps for project performance improvement.

Many oil and gas projects experienced significant cost overruns, which is a major concern for the industry. The objective of this study is to investigate the cost performance of oil and gas projects by analyzing the data of approximately 200 public oil and gas projects. The average cost overrun of the projects is 18% with a standard deviation of 29%. The results also indicate that the error of underestimation is more frequent and greater than that of the overestimation. The projects' cost performance is also examined in terms of project size, type, region, joint venture information, and Final Investment Decision (FID) year. All effects of each factor are tested with statistical methods, and various drivers for cost performances are suggested to explain the differences in cost performance. The findings of this research will provide some guidance and references for future improvement in project performance.

In this study, six core samples were obtained from the Middle Bakken Formation in North Dakota. Before the imbibition experiment, petrophysical analysis were conducted for the samples. XRD method was used to analyze the mineral composition. Nitrogen adsorption and SEM methods were combined to study the pore size distribution and microstructures. Then the authors performed brine imbibition and surfactant imbibition for six Bakken cores and two Berea sandstones. Before the experiment, the cores were fully filled with Bakken crude oil. The core plugs were then submerged into the brine and surfactant solutions with all-face-open (AFO) condition. Experiments of brine and surfactant imbibing into oil-filled cores were carried out with recording of recovered oil volume using imbibition cells. Different types of surfactants such as cationic, anionic, and nonionic, were tested in the study. Those experiments evaluate the oil displacement efficiencies of brine and different surfactants in Bakken rocks.

Abstract Geological carbon sequestration through injecting large-scale carbon dioxide (CO2) into the deep saline aquifers represents a long-term storage of CO2. In the CO2 sequestration process, the injected CO2 is displacing water from the injection point and is expected to remain in the reservoir. Due to the nature of one phase displacing another phase in porous media, it is noted that different water saturation exists in the CO2 plume during the displacement. Water distribution in the plume will affect the size of the plume subsurface. Furthermore, the gravitational segregation between CO2 and water will cause overriding-tonguing during the injection and impact the shape of plume. To better understand the CO2 movement underground and development of CO2 plume, it is necessary to take the two-phase flow and gravity force effects into account when evaluating CO2 displacing water. The displacement of water by injecting CO2 is not a piston-like process in aquifer. Because water is the wetting phase and CO2 is the non-wetting phase when two phases flow in reservoir, water occupies the surface of matrix and small pores while CO2 resides in large pores and centers of pores. As a result, various water saturations distribute behind CO2 front during the displacement. The distribution is a function of fluid and rock properties, fluid-rock interaction, and injection operation. In this study, these factors are considered when developing new models to predict CO2 plume evolution during injection. Mass conservation, multiphase flow, and equation-of-states are applied in the derivation of the models, which guarantees a rigorous approach in the investigation. The modeling results indicate that CO2 does not displace water completely away from the plume. The shape of the CO2 front is controlled by the relative permeability of two phases and capillary pressure. Water saturation profile from CO2 injecting point to the displacement front shows that water saturation behind the CO2 front increases outwardly, and the change in saturation is non-linear. The injection rate impacts the sharpness of the CO2 front, thus leads to different gas plume sizes for same injection volume. The outward movement of the CO2 front decelerates as injection time goes on. The research illustrates that injection experiences two stages: transient and steady-state, in which the displacement behavior and the development of gas plume vary. Although the duration of transient stage is dictated by size of aquifer and is relatively short comparing with steady-state stage, its influence on the development of CO2 plume cannot be neglected when selecting gas compressor horsepower and determining injection rate.

Abstract The low recovery of oil from the tight liquid-rich formations is still a main challenge for the tight reservoir. Thus, in order to break the chains and remove the obstacle such as the low recovery factor in the Bakken tight formation, even though the horizontal drilling and hydraulic fracturing technologies were already well applied in this field, the supercritical CO2 flooding was proposed as an immense potential recovery method for the production improvement. In this research, we conducted a series of CO2 flooding experiments under various injection pressure (2500psi, 2800psi, 3000psi, 3500psi), to investigate the recovery potential of the core sample from Bakken tight formation. Also, the NMR analysis was processed of the core samples flooded with CO2 agent under the above injection pressure variables. The result comparison demonstrates that, with the supercritical CO2 injection pressure increase, the recovery factor gets incremental trend from 8.8% up to 33% recovery. Also, the macro pore and natural fracture system were proved to contribute more on the recovery potential. After reaching the miscible phase between the CO2 and oil in the sample, the hydrocarbon existed in the micro pores start the contribution to the recovery potential. Thus, The CO2 was identified as a potential recovery agent and the supercritical CO2 EOR method was proposed as the potential recovery technology due to the high recovery factor obtained in the immiscible and miscible processes.

In recent years, the exploration and production of oil and gas from Bakken formation in Williston Basin have proceeded quickly due to the application of multi-stage fracturing technology in horizontal wells. Knowledge of the rock elastic moduli is important for the horizontal drilling and hydraulic fracturing. Although static moduli obtained by tri-axial compression test are accurate, the procedures are cost expensive and time consuming. Therefore, developing correlation to predict static moduli from dynamic moduli, which is calculated from sonic wave velocities, is meaningful in cutting cost and it makes the unconventional oil and gas exploration and production more efficient. Literature review indicates such a correlation is not available for Bakken formation. This may be attributed to the extremely low success rate in Bakken core sample preparation and not enough published data to develop correlation to relate dynamic moduli to static moduli. This study measures and compares the moduli obtained from sonic wave velocity tests with deformation tests (tri-axial compression tests) for the samples taken from Bakken formation of Williston Basin, North Dakota, USA. The results show that the dynamic moduli of Bakken samples are considerably different from the static moduli measured by tri-axial compression tests. Correlations are developed based on the static and dynamic moduli of 117 Bakken core samples. The cores used in this study were taken from the core areas of Bakken formation in Williston Basin. Therefore, they are representatives of the Bakken reservoir rock. These correlations can be used to evaluate the uncertainty of Bakken formation elastic moduli estimated from the seismic and/or well log data and adjust to static moduli at a lower cost comparing with conducting static tests. The correlations are crucial to understand the rock geomechanical properties and forecast reservoir performance when no core sample is available for direct measurement of static moduli.

Gaither Draw Unit is a heterogeneous and tight formation with an average permeability less than 0.1 mD. After more than 1.7 MMSTB water injection, there was no clear indication or benefit of the injected water from any producer. However, knowing the distribution of the injected water is critical for future well planning and quantifying the efficiency of injection. The objective of this study is to show how the Capacitance-Resistance Model (CRM) was used on this field and validated using other independent methods. The CRM model describes the connectivity and the degree of fluid storage quantitatively between injectors and producers from production and injection rates. Rooted in material balance, signals from injectors to producers can be captured in the CRM. Using constrained nonlinear multivariable optimization techniques, the connectivity is estimated in the selected portion of the field through signal analysis on injection and production rates. In this tight formation, the whole field is divided into seven regions with one injection well and surrounding producers to conduct CRM analysis. We further use integrated but independent approaches to validate the results from CRM. The validation includes full field modeling and history match and fluid level measurement using echometering technology. This paper focuses on a real field water flooding project in Gaither Draw Units(GDU). CRM is used to detect reservoir heterogeneity through quantifying communication between injectors and producers, and attains a production match. The fitting results of connectivity through CRM indicate permeability regional heterogeneity, which is consistent with full field modelling. The history matched full field model presents the saturation distribution showing that the majority of injected water mainly saturates the surrounding regions of injectors, and the low transmissibility slows down the pressure dissipation. Overall, the comprehensive interpretation obtained through these three independent methods is consistent, and is very useful in planning infill well drilling and future development plan for the Gaither Draw Units. This paper shows that it is critical to integrate different sources of data in reservoir management through a field case study. The experience and observations from this asset can be applied to other tight formations being developed with water flooding projects.

Flow pattern of a multi-phase flow refers to the spatial distribution of the phase along transport conduit when liquid and gas flow simultaneously. The determination of flow patterns is a fundamental problem in two-phase flow analysis, and an accurate model for gas-liquid flow pattern prediction is critical for any multiphase flow characterization as the model is used in many applications in petroleum engineering. The objective of this study is to present a new model based on machine learning techniques and more than 8000 laboratory multi-phase flow tests. The flow pattern is affected by fluid properties, in-situ flow rates of liquid and gas, and flow conduit geometry and mechanical properties. Laboratory data since 1950s have been collected and more than 8000 data points had been obtained. However, the actual flow conditions are significantly different with any laboratory settings. Therefore, several dimensionless variables are derived to characterize these data points first. Then machine learning techniques were applied on these dimensionless variables to develop the flow pattern prediction models. Applying hydraulic fundamentals and dimensional analysis, we developed dimensionless numbers to reduce number of freedom dimensions. These dimensionless variables are easy to use for upscaling and have physical meanings. We converted the collected data from actual laboratory measurement to the variations of these dimensionless variables. Machine learning techniques on the dimensionless variable significantly improved their predictive accuracy. Currently the best matching on these laboratory data was about 80% using the most recently developed semi-analytical models. Using machine learning techniques, we improved the matching quality to more than 90% on the experimental data. This paper applies machine learning techniques on flow pattern prediction, which has tremendous practical usages and scientific merits. The developed model is better than current existing semi-analytical or classical correlations in matching the laboratory database.

Nowadays, unloading gas wells with coiled tubing is a common application to the field. However, it still lacks of adequate understanding of dynamic behavior of the unloading process. This paper investigates the process of liquid unloading by gas lift with coiled tubing under transient conditions. This unloading process can be divided into three stages: liquid rising in tubing, liquid slug production, and liquid production by entrainment. In each stage, the mass and conversation equations are applied as governing equations. The components of each stage include coiled tubing, coiled tubing-tubing annulus, liquid slug, gas bubble, and liquid film. Empirical correlations have been used for surface gas injection choke, check valve, friction factor, the relationship between the gas bubble and the liquid slug velocity, inflow performance relationship, and black oil fluid properties. From the above, the dynamic model coupling real-time change of inflow performance relationship is developed. The lower upper (LU) factorization and Euler's method are applied to solve the proposed dynamic model in time domain. Among all these variables, the most important ones include gas injection rates, pressures at various locations, length of the liquid slug and gas bubble, and phase velocities. Through the simulation efforts, the mechanism of liquid unloading process is revealed. Gas lift is commonly constrained by gas availability. This is a pioneering study on liquid unloading with coiled tubing. The results can be applied to design coiled tubing gas lift to optimize the usage of injected gas, choose appropriate pump, and save the energy consumed in gas lift operation.

The increasing development of unconventional resources plays an important role in filling the gap between demand and conventional oil and gas supply. Due to the nature of low permeability, tight gas and shale reservoirs need fractures, natural and artificial, to produce hydrocarbon at commercial rates. Fracture permeability is a key factor affecting the development of these unconventional reservoirs. It is observed that fracture permeabilities decline as reservoirs are depleted because pore pressure declines lead to the closures of fractures and the permeability reductions. Therefore a correlation to quantify the variations of the fracture permeability with pore pressure is highly needed. In this study we investigate the effects of pore pressures on fracture permeabilities assuming constant in-situ stresses exert on the formations. Starting from the force balance, we derived equations to calculate fracture permeability based on fracture geometry. Our new correlations can also be used to evaluate the changing fracture permeability during the recovery of hydrocarbon. The proposed correlations provide a way to estimate the fracture permeability at initial pressure and the depleted pressure at any production stage. Although some experiments had been conducted to build relationships between fracture permeability and pressure for some types of rocks. It is noted that experiments are time consuming and cost expensive. Sometimes, the unavailability of shale sample and difficulty in preparing shale core plug also limit the number of experiment. Our research provided a theoretical model. We realize that theoretical results are not necessarily the ground truth because of the many implicit and explicit assumptions made to obtain an analytical formula. Therefore, extensive sensitivity study was conducted to quantify the effects of important parameters on permeability change. The proposed methods considered the laminar flow as well as turbulent flow in the fracture, which is often observed in gas well. Under the conditions of no core sample available to test the impact of pressure on fracture permeability, or special core analyses prohibited by cost and time, the proposed correlations are powerful tools to estimate the change of permeability with producing time.

In recent years, the development of oil and gas from shale has proceeded quickly in the world through the use of multistage fracturing technology in horizontal well. However, without the knowledge of rock poroelastic characteristics, the successful rate of hydraulic fracturing will be low. Among those poroelastic characteristics, effective stress is required for creating artificial fractures in the shale formation. In this study a new method is proposed to measure the Biot's coefficient, which is one of the key poroelastic parameters for calculating the effective stress. The Biot's coefficient is obtained after the variations of both the confining and the pore pressures are recorded with a simplified measuring procedures. The Bakken shale samples from Williston Basin are tested. The experiment results show that the Biot's coefficient of Bakken samples obtained from horizontal drilling and vertical drilling are significantly different from each other. This provides a solid base to scientists and engineers for Bakken in-situ stress analysis during multistage hydraulic fracturing and reservoir depletion due to production.

In petroleum exploration and production, knowledge of geomechanical properties of target reservoirs ensures producing hydrocarbon safely and economically, and protecting environmental friendly. Rock compressibility, one of the geomechanical properties, is an essential parameter in drilling and completion design. Because direct measurements of rock compressibility are time consuming and cost expensive, indirect measurements from other readily available experimental data are highly demanded. When direct measurements are unavailable or experimental data are unreliable due to lab and human errors, irregular core plug, and/or non-uniform deformation, obtaining rock compressibility from other methods is not only a good reference for the directly measured rock compressibility but also an important supplement to those indirect methods. In this study, a method with solid theoretical base is developed to determine rock compressibility using permeability experimental data. With that, core analysis can be more reliable and accurate. The combination of the proposed method with direct measurements can be employed to ensure the reliability of the experiment and to quantify the uncertainty resulting from lab and human errors.

The free gas evolved in the pump chamber results in a low rod pump working efficiency, and it can even lead to a failure. A common and effective solution is to install a downhole gas separator before fluid entering the chamber, which can divert the free gas to the annulus. If we can re-inject the diverted gas back to the tubing at a shallower depth above the pump, the flowing gas is then re-combined with the liquid and decreases fluid density. Consequently, the injected gas also creates additional lifting drive for the liquid. A new technology based on this concept has been developed and called Casing Gas Assisted Rod Pumping (CGARP). This paper firstly presents an analytical model to optimize the overall lifting performance and minimize the operating expenditure. It is especially useful in producing hydrocarbon at high GOR. As the gas is re-combined with the liquid above the pump installation depth, the hydrostatic pressure gradient is reduced consequently. However, if the gas reinjection valve is placed at a shallow depth, the well segment at reduced fluid density is subsequently short, so the contribution of gas lift is restricted. Vice versa, if the gas reinjection valve is placed at the depth close to the pump, it requires high pressure to open the gas injection valve, so the gas reinjection can happen infrequently and the production rate is unsfplease. This paper has proposed a genetic optimization method to maximize the overall production system efficiency. A multi-variable vector has been defined, which includes pumping speed and depth, mechanical power, rod string diameter and length, surface stroke length, downhole separator efficiency, as well as gas reinjection valve depth. The optimized object can be the system lifting efficiency or Net Present Value, which must be a function of this vector in the constraint of mass and momentum conservations. This work has been applied as the primary guide for four oil producers with rod pump installed in Jilin field, China. The average system lifting efficiency and production rate have been increased by 20% and 15% respectively. This analytical model has enhanced the field performance. Most importantly, the same concept can be applied for other pump-assisted wells.

Brittleness is a key factor in identifying intervals and areas for fracking in tight oil and gas reservoirs. The brittleness index of reservoir rocks can be calculated by elastic properties, but laboratory measurement of elastic properties is usually expensive and time consuming. In this paper, a method is proposed to predict the brittleness from known mineralogy and applied to assess the upper Three Forks formation in the Williston basin. In this method, a correlation between the elastic properties of the formation rock and mineralogy was first established based on rule of mixture. This correlation was verified by the measured elastic properties of the middle Bakken member. Then the correlating approach was used to predict the elastic property-based brittleness index of the upper Three Forks formation. The results indicate that the upper Three Forks formation should be conducive to reservoir stimulation as its predicted brittleness index ranges from 53 to 67 in the direction parallel to the bedding plane and 58 to 70 in the direction perpendicular to the bedding plane. Its brittleness is comparable to that of the middle Bakken member, which has been already successfully stimulated. The correlating method presented in this paper is also applicable to other major tight reservoirs.

In recent years, petroleum exploration and production from the Williston Basin at the Bakken Formation has garnered great success. Producing hydrocarbons from the Bakken Formation is challenging due to its low porosity and permeability. Investigating the permeability of the Bakken Formation is required in order to better understand the performance of wells that produce hydrocarbons. In addition, permeability is one of the key parameters in modeling fluids flow in reservoir simulation matrices. Unfortunately, the measurement of permeability of tight rocks, such as in Bakken samples, is time consuming and expensive due to their low to extremely low permeability; in addition, sometimes the results from different methods are not in good agreement. Because of the high uncertainty in measuring the permeability of tight rock, it is worthwhile to investigate permeability through different methods in order to reduce uncertainty. In this study, we measured the permeability of tight rocks utilizing three different methods with the same setup. The investigated methods were the oscillating pulse method, the downstream pressure buildup method, and the radius-of-investigation method. In this way, the comparison provides uncertainty and magnitude and indicates the possible presence of heterogeneities and lamination.

Buckley–Leverett displacement equations have been derived strictly from linear flow systems, and have been verified by linear flow experiments only. This paper presents analytical algorithms to calculate recovery factors for radial flow systems, which is expected to be more accurate for peripheral water-flooding reservoirs. The proposed equations have been verified with field data. The original Buckley–Leverett equation generally results in much lower recovery factors that barely match the well cumulative production at interest. Consequently, the estimated ultimate recovery (EUR) by volumetric methods tends to be low. As a result, the production projection according to volumetric EUR is not reasonable in comparing to the historical performance. The proposed analytical model improves the prediction of reservoir performance.

• A method using permeability measurement to determine pore compressibility was proposed.

Inability to accurately model fundamental governing flow equation in a hole has resulted in erotic evaluation of flowing and shut-in bottom hole pressures (BHPs) for aerated fluid drilling in borehole. It is of practical important to derive an exact model for this case without ignoring any pressure resisting terms in the governing thermodynamic equation so as to enhance well control efficiently. An improved hydraulics model has been derived to demonstrate the impact of neglected pressure restriction due to kinetic energy and fluid accumulation in the fundamental energy equation used for predicting flowing and shut-in bottom-hole pressures for aerated mud drilling in petroleum well. These neglected terms have conceived to be a vital reason for the eroneous result between computed value from the existing models and actual value generated from field. The developed model has been tested using the same dataset obtained from the field of investigation by Guo et al and more desirable outcomes were got from the new model than the previous investigators with error margin of 2.7%. Realistic results that evident all pressure transverse behaviors after shut-in for aerated mud drilling in well which include the initial constant pressure regime, unsteady regime, semi-steady regime and stabilized state condition hence pressure transverse at any period of drilling operation has been established. The improved model has demonstrated that inaccuracy in the results of existing models were not only caused by the effect of pressure restriction due to friction as opined by Guo et al but may have due to oversight of all pressure restriction terms in the fundamental equation that govern flow of aerated drilling fluid in petroleum well. The new concept is useful for drilling engineers to estimate flowing and shut in bottom-hole pressure for better control of well stability at all flow conditions during aerated mud underbalanced drilling.

The pipeline safety management system is crucial to transfer oil and gas because the phenomena of leakage commonly occurs in the long-distant pipelines. Hidden safety hazards can be caused by design and construction defects, affected by natural disasters, or corroded by the transmission fluid. Therefore, quick detection will not only reduce the loss of transported oil and gas but also can protect the local environment. In this study, we develop a new method to detect the pipeline leak by analyzing pressure distribution through the leak. Pipeline leak detection tests are operated using a flow loop. Through the experiments, four parameters which are pressures and flow rates of pipeline inlet and outlet are recorded. Then the specific location of the leak is determined by dimensionless analysis of flow parameters. To generate the solution to locate the leak, we introduce three dimensionless variables, which are dimensionless leak location, dimensionless leak rate, and dimensionless pressure drop. Then the relationship of pressure distribution and leak parameters is built through the simulation models. After running 3D computational fluid dynamics (CFD) simulations with commercial software (FLUENT), the pressure distribution in the pipeline with leakage in the experiments will be verified by the experimental data. Finally, the mathematical models are developed to detect and evaluate the leakage through the pipeline. CFD simulation results show that both the leak rate and location have significant effects on the pressure distribution through the pipe, which is identical to the outcome from the experiments. When the dimensionless leak location is smaller or the dimensionless leak rate is larger, the dimensionless pressure drop is smaller. The mathematical model which is based on these dimensionless variables can be applied in locating the leak point in the real accident.