Miscible Gas Research Articles

To optimize well pattern during miscible gas injection process via heuristic techniques

To detect optimum well locations for new injection wells one must generally notice to existing well locations, reservoir shape, capital cost per well construction in each area as well as recovery increase relevant to new well layout. Designing injection process presents inverse optimization issue whereas adjusting exploitation wells prior to primary recovery exhibits classic optimization problem. Most important design factor namely injection well layout has no unique explicit solution to solve via analytical or numerical techniques thus one can propose meta or hyper heuristic approaches to solve such problems. Our main novelty in this work is that here we cooperate four heuristic optimization approaches with our self made fast simulation technique to optimize well locations for two exemplar miscible gas injection processes. We employ MATLAB software to construct artificial porous media prototypes with different uncertainties to investigate optimization technique performances in low rather than high risk media. Outcomes illustrate that approaches like artificial immune system or particle swarm optimization which exhibit strong local search can effectively detect optimal well locations in high risk porous media. Results also show that solution techniques such as Monte Carlo that have strong global search capabilities at expense of weak local search can discover optimum well locations only in media with low uncertainty.

A Comprehensive Performance Evaluation Methodology for Miscible Gas Flooding: A Case Study in a Giant Carbonate Reservoir in Middle East

A Comprehensive Performance Evaluation Methodology for Miscible Gas Flooding: A Case Study in a Giant Carbonate Reservoir in Middle East

Asphaltene Thermodynamic Precipitation during Miscible Nitrogen Gas Injection

SummaryFor many years, miscible gas injection has been the most beneficial enhanced oil recovery method in the oil and gas industry. However, injecting a miscible gas to displace oil often causes the flocculation and deposition of asphaltenes, which subsequently leads to a number of production problems. Nitrogen gas (N2) injection has been used to enhance oil recovery in some oil fields, seeking to improve oil recovery. However, few works have implemented N2 injection and investigated its effect on asphaltene precipitation and deposition. This research investigated the N2 miscible flow mechanism in nanopores and its impact on asphaltene precipitations, which can plug pores and reduce oil recovery. First, a slimtube was used to determine the minimum miscibility pressure (MMP) of N2 to ensure that all of the experiments would be conducted at levels above the MMP. Second, filtration experiments were conducted using nanocomposite filter membranes to study asphaltene deposition on the membranes. A filtration apparatus was designed specifically and built to accommodate the filter membranes. The factors studied include N2 injection pressure, temperature, N2 mixing time, and pore size heterogeneity. Visualization tests were conducted to highlight the asphaltene precipitation process over time. Increasing the N2 injection pressure resulted in an increase in the asphaltene weight percent in all experiments. Decreasing the pore size of the filter membranes increased the asphaltene weight percent. More N2 mixing time also resulted in an increase in asphaltene weight percent, especially early in the process. Visualization tests revealed that after 1 hour, the asphaltene particles were conspicuous, and more asphaltene clusters were found in the test tubes of the oil samples from the filter with the smallest pore size. Chromatography analysis of the produced oil confirmed the reduction in the asphaltene weight percent. Microscopy and scanning electron microscopy (SEM) imaging of the filter membranes indicated significant pore plugging from the asphaltenes, especially for the smaller pore sizes. This research highlights the severity of asphaltene deposition during miscible N2 injection in nanopore structures so as to understand the main factors that may affect the success of miscible N2 injection in unconventional reservoirs.

A hybrid FAHP-MCGP approach to sustainable assessment of candidate EOR methods for a given oil reservoir

During the past decades, growing global demand for crude oil, staggering costs of exploration of new reservoirs, and gradual decreasing natural pressure inside mature reserves have made oil companies interested in using enhanced oil recovery (EOR) technologies to improve recovery factor. Like other oil and gas industry operations, observance of sustainable development criteria is a serious challenge for EOR projects. In reality, most of these criteria introduce themselves as qualitative features of the problem, and evaluating EOR scenarios based on them is more subjective. Also, these criteria may have various relative weights. Furthermore, due to the uncertainty and scarcity of precise data, decision-makers may not set a single aspiration for each criterion and prefer to set an aspiration level for every objective. In view of this argument, this paper suggests a hybrid framework to assess and prioritize the different EOR scenarios for a given oil reservoir from a sustainability point of view. Firstly, based on an extensive review of the literature, a comprehensive set of sustainability criteria for screening EOR projects was developed. Afterward, a Fuzzy Analytic Hierarchy Process (FAHP) was applied to determine the relative weights of the most influencing sustainability criteria, according to the judgments provided by experts from relevant fields. Finally, a Multi-Choice Goal Programming (MCGP) model was utilized for prioritizing the performance of EOR methods based on minimum unwanted deviation from aspiration levels for objectives considered in the problem. The findings reveal that the hydrocarbon miscible gas injection is the best choice and CO2 miscible gas injection is the least favorable choice. The present study provides a helpful and straightforward decision-making tool for quantitative and qualitative evaluation of EOR scenarios.

Fast Optimization of Injector Selection for Waterflood, CO2-EOR and Storage Using an Innovative Machine Learning Framework

Optimal injector selection is a key oilfield development endeavor that can be computationally costly. Methods proposed in the literature to reduce the number of function evaluations are often designed for pattern level analysis and do not scale easily to full field analysis. These methods are rarely applied to both water and miscible gas floods with carbon storage objectives; reservoir management decision making under geological uncertainty is also relatively underexplored. In this work, several innovations are proposed to efficiently determine the optimal injector location under geological uncertainty. A geomodel ensemble is prepared in order to capture the range of geological uncertainty. In these models, the reservoir is divided into multiple well regions that are delineated through spatial clustering. Streamline simulation results are used to train a meta-learner proxy. A posterior sampling algorithm evaluates injector locations across multiple geological realizations. The proposed methodology was applied to a producing field in Asia. The proxy predicted optimal injector locations for water and CO2 EOR and storage floods within several seconds (94–98% R2 scores). Blind tests with geomodels not used in training yielded accuracies greater than 90% (R2 scores). Posterior sampling selected optimal injection locations within minutes compared to hours using numerical simulation. This methodology enabled the rapid evaluation of injector well location for a variety of flood projects. This will aid reservoir managers to rapidly make field development decisions for field scale injection and storage projects under geological uncertainty.

Gas flow study for development of a novel shielding gas nozzle for directed energy deposition processes using computational fluid dynamic simulations

Directed energy deposition (DED) enables the additive manufacturing of several materials such as molybdenum alloys that are very difficult to process by conventional methods. Some of these materials are highly reactive to gases in ambient atmosphere such as oxygen, and nitrogen. Oxidation during additive manufacturing significantly influences the mechanical properties of a part. In some cases, the shielding gas coverage of standard powder nozzles is not sufficient, and oxidation still takes place. A functional prototype of a compound multi flow path annular nozzle was developed using computational fluid dynamics simulations. Simulations were performed using multi-component miscible gas model. Prototypes were manufactured for several design iterations to test their functionality in cold flow conditions. In the end, an Inconel based prototype was built, using laser powder bed fusion. The volume of shielding gas cover over the substrate improved with the proposed design and the radial extent of 80 ppm oxygen concentration increased from 8 mm to 25 mm. Finally, Mo-Si-B alloy was deposited on a 1000 °C pre-heated substrate without significant oxidation or cracks.

Phase Behavior Analysis of CO2 and Formation Oil System

In this paper, there are nine oil samples to explore the characteristics of formation oil at different CO2 injection rate, and the characteristics include bubble point pressure, volume expansion coefficient, viscosity, density, and average molecular weight, composition of gas and liquid phase, and asphalt sediment. According to the experimental results of early nine oil samples of swelling tests, in high temperature and high pressure conditions, characteristics and changing rules of properties of formation oil, including bubble point pressure, volume expansion coefficient, viscosity, density, and average molecular weight, composition of gas and liquid phase, and asphalt sediment, were evaluated and analyzed at different CO2 injection rate systematically. The research not only can provide guides for petroleum engineers when they need to adjust the injection and production programs, but also can provide comparatively comprehensive experimental rules for researches on enhanced oil recovery (EOR) mechanisms of gas miscible and nonmiscible flooding. Moreover, phase parameters of different formation oil system can be extracted for reservoir numerical simulation.

How Is Ultrasonic-Assisted CO2 EOR to Unlock Oils from Unconventional Reservoirs?

CO2 enhanced oil recovery (EOR) has proven its capability to explore unconventional tight oil reservoirs and the potential for geological carbon storage. Meanwhile, the extremely low permeability pores increase the difficulty of CO2 EOR and geological storage processing in the actual field. This paper initiates the ultrasonic-assisted approach to facilitate oil–gas miscibility development and finally contributes to excavating more tight oils. Firstly, the physical properties of crude oil with and without ultrasonic treatments were experimentally analyzed through gas chromatography (GC), Fourier-transform infrared spectroscopy (FTIR) and viscometer. Secondly, the oil–gas minimum miscibility pressures (MMPs) were measured from the slim-tube test and the miscibility developments with and without ultrasonic treatments were interpreted from the mixing-cell method. Thirdly, the nuclear-magnetic resonance (NMR) assisted coreflood tests were conducted to physically model the recovery process in porous media and directly obtain the recovery factor. Basically, the ultrasonic treatment (40 KHz and 200 W for 8 h) was found to substantially change the oil properties, with viscosity (at 60 °C) reduced from 4.1 to 2.8 mPa·s, contents of resin and asphaltene decreased from 27.94% and 6.03% to 14.2% and 3.79%, respectively. The FTIR spectrum showed that the unsaturated C-H bond, C-O bond and C≡C bond in macromolecules were broken from the ultrasonic, which caused the macromolecules (e.g., resin and asphaltenes) to be decomposed into smaller carbon-number molecules. Accordingly, the MMP was determined to be reduced from 15.8 to 14.9 MPa from the slim-tube test and the oil recovery factor increased by an additional 11.7%. This study reveals the mechanisms of ultrasonic-assisted CO2 miscible EOR in producing tight oils.

Effect of Functional Groups on Chemical-Assisted MMP Reduction of a Methane-Oil System

Natural gas injection (i.e., recycling) is a commonly used for enhanced oil recovery method and is potentially cost-effective and efficient. However, natural gas injection, particularly methane, often has a high minimum miscibility pressure (MMP) which likely exceeds the fracture pressure of many otherwise viable reservoirs. Therefore, this work aims to investigate the potential of chemical-assisted MMP reduction of the methane-oil system to expand the application of miscible natural gas injection to more candidate reservoirs. In this context, we performed a study to test six potential surfactant-like chemicals with different polar headgroups (i.e., morpholine, aromatic sulfonic acid, aromatic carboxylic acid, and 2-oxypyrrolidine). The intent is to reduce the methane-oil interfacial tension using the vanishing interfacial tension method at a constant temperature of 373 K. First, at a concentration of 2 wt %, we tested the effect of the polar headgroups with the same hydrocarbon chain. Then, we investigated the effect of increasing the hydrocarbon chain length on the methane-oil miscibility. Our results show that chemical additives with the 2-oxopyrrolidine and aromatic sulfonic acid functional groups give higher MMP reductions (8.7–9.6%, respectively) compared with aromatic carboxylic acid and morpholine groups, which only give limited or no MMP reduction. Moreover, the results show that the reduction in first contact miscibility pressure is higher (12.8–19.1%) compared to MMP. Furthermore, increasing the hydrocarbon chain length (from 10 to 13) of the 2-oxopyrrolidine and aromatic sulfonic acid molecules seems to decrease the efficiency in reducing MMP. Our results screen the potential of a combinatorial chemistry approach (where two molecules with differing sizes and functional groups can be readily joined together to make a large library of compounds) that can be used to identify chemical additives for reducing MMP of methane-oil. This approach underscores the importance of optimizing the functional group and hydrocarbon chain length in potential chemicals for MMP reduction. The outlined research results likely expand the application of miscible natural gas injection to deep and/or high-temperature reservoirs, in addition to the environmental benefits of reducing gas flaring and greenhouse gas emissions through natural-gas recycling.

Nanopore Confinement Effect on the Phase Behavior of CO2/Hydrocarbons in Tight Oil Reservoirs considering Capillary Pressure, Fluid-Wall Interaction, and Molecule Adsorption

The pore sizes in tight reservoirs are nanopores, where the phase behavior deviates significantly from that of bulk fluids in conventional reservoirs. The phase behavior for fluids in tight reservoirs is essential for a better understanding of the mechanics of fluid flow. A novel methodology is proposed to investigate the phase behavior of carbon dioxide (CO2)/hydrocarbons systems considering nanopore confinement. The phase equilibrium calculation is modified by coupling the Peng-Robinson equation of state (PR-EOS) with capillary pressure, fluid-wall interaction, and molecule adsorption. The proposed model has been validated with CMG-Winprop and experimental results with bulk and confined fluids. Subsequently, one case study for the Bakken tight oil reservoir was performed, and the results show that the reduction in the nanopore size causes noticeable difference in the phase envelope and the bubble point pressure is depressed due to nanopore confinement, which is conductive to enhance oil recovery with a higher possibility of achieving miscibility in miscible gas injection. As the pore size decreases, the interfacial tension (IFT) decreases whereas the capillary pressure increases obviously. Finally, the recovery mechanisms for CO2 injection are investigated in terms of minimum miscibility pressure (MMP), solution gas-oil ratio, oil volume expansion, viscosity reduction, extraction of lighter hydrocarbons, and molecular diffusion. Results indicate that nanopore confinement effect contributes to decrease MMP, which suppresses to 650 psi (65.9% smaller) as the pore size decreases to 2 nm, resulting in the suppression of the resistance of fluid transport. With the nanopore confinement effect, the CO2 solution gas-oil ratio and the oil formation volume factor of the oil increase with the decrease of pore size. In turn, the oil viscosity reduces as the pore size decreases. It indicates that considering the nanopore confinement effect, the amount of gas dissolved into crude oil increases, which will lead to the increase of the oil volume expansion and the decrease of the viscosity of crude oil. Besides, considering nanopore confinement effect seems to have a slightly reduced effect on extraction of lighter hydrocarbons. On the contrary, it causes an increase in the CO2 diffusion coefficient for liquid phase. Generally, the nanopore confinement appears to have a positive effect on the recovery mechanisms for CO2 injection in tight oil reservoirs. The developed novel model could provide a better understanding of confinement effect on the phase behavior of nanoscale porous media in tight reservoirs. The findings of this study can also help for better understanding of a flow mechanism of tight oil reservoirs especially in the case of CO2 injection for enhancing oil recovery.

Well Performance from Numerical Methods to Machine Learning Approach: Applications in Multiple Fractured Shale Reservoirs

Horizontal well fracturing technology is widely used in unconventional reservoirs such as tight or shale oil and gas reservoirs. Meanwhile, the potential of enhanced oil recovery (EOR) methods including huff-n-puff miscible gas injection are used to further increase oil recovery in unconventional reservoirs. The complexities of hydraulic fracture properties and multiphase flow make it difficult and time-consuming to understand the well performance (i.e., well production) in fractured shale reservoirs, especially when using conventional numerical methods. Therefore, in this paper, two methods are developed to bridge this gap by using the machine learning technique to forecast well production performance in unconventional reservoirs, especially on the EOR pilot projects. The first method is the artificial neural network, through which we can analyze the big data from unconventional reservoirs to understand the underlying patterns and relationships. A bunch of factors is contained such as hydraulic fracture parameters, well completion, and production data. Then, feature selection is performed to determine the key factors. Finally, the artificial neural network is used to determine the relationship between key factors and well production performance. The second is time series analysis. Since the properties of the unconventional reservoir are the function of time such as fluid properties and reservoir pressure, it is quite suitable to apply the time series analysis to understand the well production performance. Training and test data are from over 10000 wells in different fractured shale reservoirs, including Bakken, Eagle Ford, and Barnett. The results demonstrate that there is a good match between the available and predicated well performance data. The overall R values of the artificial neural network and time series analysis are both above 0.8, indicating that both methods can provide reliable results for the prediction of well performance in fractured shale reservoirs. Especially, when dealing with the EOR field cases, such as huff-n-puff miscible gas injection, Time series analysis can provide more accurate results than the artificial neural network. This paper presents a thorough analysis of the feasibility of machine learning in multiple fractured shale reservoirs. Instead of using the time-consuming numerical methods, it also provides a more robust way and meaningful reference for the evaluation of the well performance.

Modeling non‐isothermal two‐phase fluid flow with phase change in deformable fractured porous media using extended finite element method

AbstractIn this article, a computational model is presented for the analysis of coupled thermo‐hydro‐mechanical process with phase change (evaporation/condensation) in fractured porous media in order to model multiphase fluid flows, heat transfer, and discontinuous deformation by employing the extended finite element method. The ideal gas law and Dalton's law are employed to consider vapor and dry air as miscible gases. To take into account the phase change, latent heat and specific vapor enthalpy are incorporated into the physical model. The set of governing equations consists of linear momentum for the solid‐phase, energy balance equation and mass conservation equations of water species (liquid and vapor) and dry air, which are derived within the framework of the generalized Biot's theory. The weak forms are presented in terms of the displacement, water pressure, capillary pressure, and temperature as the primary variables. The spatial and temporal discretizations are carried out applying the extended finite element method and the generalized Newmark scheme, respectively, resulting in the final system of fully coupled nonlinear equations. Finally, several numerical examples are solved to demonstrate not only the robustness of the proposed computational model but also the effect of the crack orientation, intrinsic permeability, and elastic modulus on the fluid flow patterns, relative humidity, and temperature distribution. Moreover, an edge‐crack propagation is investigated under mode I fracture due to drying conditions.

Laboratory Investigation of Permeability Impairment Caused by Asphaltene Precipitation during Screening for Gas-Injection Enhanced Oil Recovery and Pressure Change in a Major Gulf of Mexico Field

Summary As part of studying miscible gas injection (GI) in a major field within the Green Canyon protraction area in the Gulf of Mexico (GOM), asphaltene-formation risk was identified as a key factor affecting a potential GI project. The industry has not conducted many experiments to quantify the effect of asphaltenes on reservoir and well performance under GI conditions. In this paper we discuss a novel laboratory test for evaluating the asphaltene effect on permeability. The goals of the study were to define the asphaltene-precipitation envelope using blends of reservoir fluid and injection gas, and measure permeability reduction caused by asphaltene precipitation in a core under GI. To properly analyze the effect of GI, a suite of fluid-characterization studies was conducted, including restored-oil samples, compositional analysis, constant composition expansion (CCE), and differential vaporization. Miscibility conditions were defined through slimtube-displacement tests. Gas solubility was determined through swelling tests complemented by asphaltene-onset-pressure (AOP) testing. The unique procedure was developed to estimate the effect of asphaltene deposition on core permeability. The 1-ft-long core was saturated with the live-oil and GI mixture at a pressure greater than the AOP, and then pressure was depleted to a pressure slightly greater than the bubblepoint. Several cycles of charging and depletion were conducted to mimic continuous flow of oil along the path of injected gas and thereby to observe the accumulation of asphaltene on the rock surface. The test results indicated that during this cyclic asphaltene-deposition process, the core permeability to the live mixture decreased in the first few cycles but appeared to stabilize after Cycle 5. The deposited asphaltenes were analyzed further through environmental scanning electron microscopy (ESEM), and their deposition was confirmed by mass balance before and after the tests. Finally, a relationship was established between permeability reduction and asphaltene precipitation. The results from the asphaltene-deposition experiment show that for the sample, fluids, and conditions used, permeability is impaired as asphaltene flocculates and begins to coat the grain surfaces. This impairment reaches a plateau at approximately 40% of the initial permeability. Distribution of asphaltene along the core was measured at the end by segmenting the core and conducting solvent extraction on each segment. Our recommendation is numerical modeling of these test results and using this model to forecast the magnitude of the permeability impairment in a reservoir setting during miscible GI.

Sensitivity Analysis and Multiobjective Optimization of CO2 Huff-N-Puff Process after Water Flooding in Natural Fractured Tight Oil Reservoirs

The CO2 huff-n-puff is an effective substitute technology to further improve oil recovery of natural fractured tight oil reservoirs after water flooding, for its high displacement efficiency and superior injectivity. The CO2 huff-n-puff process is influenced by many factors, such as miscible degree, complex fracture networks, and production schemes. What is worse, those influence facts affect each other making the process more complex. Many researchers concentrated on mechanisms and single sensitivity analysis of CO2 huff-n-puff process, whereas few optimized this process with the consideration of all influence factors and multiobjective to get favorable performance. We built multiobjective consisted of miscible degree, oil recovery, and gas replacing oil rate considering the aspects of CO2 flooding special characteristic, technical effectiveness, and economic feasibility, respectively. We have taken Yuan 284 tight oil block as a case, firstly investigated sensitivity analysis, and then optimized CO2 huff-n-puff process using orthogonal experiment design with multifactors and multiobjectives. The optimization results show CO2 huff-n-puff can significantly improve oil recovery by 8.87% original oil in place (OOIP) compared with water flooding, which offers guidelines for field operations.

Mini Review of Miscible Condition Evaluation and Experimental Methods of Gas Miscible Injection in Conventional and Fractured Reservoirs

Nowadays, one of the most efficient ways of enhanced oil recovery (EOR) is gas miscible injection (GMI). In GMI, minimum miscible pressure (MMP) is the most substantial parameter. The MMP can be estimated by different methods, such as laboratory methods, using the equation of states (EOS), empirical correlations, mathematical models, and artificial intelligence. Among these, laboratory methods of estimating MMP comprise slim tube displacement (STD), rising bubble apparatus (RBA), vanishing interfacial tension (VIT), X-ray computerized tomography (CT), fast fluorescence-based microfluidic (FFBM) method, magnetic resonance imaging (MRI), sonic response method (SRM), rapid pressure increase (RPI), oil droplet volume measurement (ODVM), and pressure–composition diagrams (PCDs), all of which are described in detail in this paper. Furthermore, experimental investigations performed using the mentioned laboratory methods have been presented. On the other hand, to perform miscible injection experiments in the matrix–fracture system, there are methods, such as fractured core plug (FCP), matrix–fracture system (MFS), modified core holder (MCH), and microconsolidation device (MCD), that the accomplished studies by the mentioned method have surveyed. Eventually, it can be deduced that, owing to the difference between the MMP in conventional and fractured reservoirs, a reliable method (laboratory or mathematical model) for estimating the MMP in fractured reservoirs is required.

Enhanced oil recovery application in low permeability formations by the injections of CO2, N2 and CO2/N2 mixture gases

Low oil recovery which is very predominant in shale oil reservoirs has stimulated petroleum engineers to investigate the applications of enhanced oil recovery methods in these formations. One such application is the injection of gases into the formation to stimulate increased oil recovery. In many gas flooding projects performed in the field, the miscibility of the gas injected is usually the most desired displacement mechanism, and carbon dioxide (CO2) gas has been recognized to be the best performing gas for injection due to its ability to be miscible with oil in the reservoir at low pressures compared to other gases such as nitrogen. This minimum miscibility pressure (MMP) is of very crucial importance because it is the primary limiting factor in the feasibility of a miscible gas flooding project. However, there are other limiting factors such as cost and availability and, in these instances, nitrogen (N2) and lean gas are the more preferred candidate as opposed to carbon dioxide gas. Mixing carbon dioxide gas with lean gas or with nitrogen in a required ratio can allow us to design an injection gas that will be suitable enough to satisfy both the availability and cost constraints and at the same time allow us to achieve a reachable and reasonable miscibility pressure. The objective of this paper is to investigate the effect of mixing nitrogen gas and carbon dioxide gas in a 50:50 ratio on oil recovery in tight oil formations. The experiment was performed with controlled constraints such as the same core sample, same crude oil and same core cleaning and saturation process which was repeated for each trial. The oil used was live oil from Eagle ford formation, and the gases used were nitrogen (99.9% purity), carbon dioxide and a mixture of nitrogen and carbon dioxide in a 50:50 ratio. The injection pressure ranged from 1000 to 5000 psi with pressure increments of 1000 psi, and the same flooding time was 6 h. The potential of the N2, CO2 and N2–CO2 mixture for improving oil recovery was assessed along with the breakthrough time. The results showed that CO2 gas had the highest recovery followed by the N2–CO2 mixture and N2 gas had the lowest recovery. The gas breakthrough time results showed that the N2–CO2 mixture had the longest breakthrough time, N2 had the shortest breakthrough time, and CO2 had a significantly longer breakthrough time than pure N2 gas. The RF increased with increasing pressure, but the gas breakthrough time decreased with increasing pressure. However, the incremental RF decreased in all three cases when the injection pressure was above 3000 psi.

Optimal Wellbore Placement of a Penta-Lateral Well in the Schrader Bluff Reservoir, North Slope, Alaska

Summary A significant oil resource exists within the Schrader Bluff and stratigraphic equivalent West Sak reservoirs located on the central North Slope of Alaska. The Schrader Bluff resource is under development in the Kuparuk River Unit, Milne Point, and within the Prudhoe Bay Unit. These areas have developed reservoirs with oil viscosities up to 200 cp under waterflood and viscosity-reducing miscible gas injection. A grass roots penta-lateral gas-lifted producer was drilled and completed to unlock untapped oil in the northern portion of the Polaris S-Pad Schrader Bluff viscous oil reservoir in Prudhoe Bay, Alaska. This producer was the first multilateral well drilled in the Orion and Polaris Schrader Bluff reservoirs in ≈8 years. The team worked to unlock surface and subsurface opportunities, delivering a substantially lower cost of access than planned. Production rate from Schrader Bluff reservoir wells has a positive correlation with contacted net sandstone. Optimal well placement in each of the five laterals was key to the delivery of a successful project. A novel approach to geosteering was used to maximize net sandstone exposure, utilizing deep azimuthal resistivity and real-time user-guided multilayered inversion modeling.

Przegląd kierunków rozwoju biochemicznych metod wspomagania wydobycia ropy naftowej ze złóż ropnych

Crude oil, a major source of energy, is being exploited as a driver of the economy throughout the world. Being a limited resource, the price of crude oil increases constantly and the exploitation of mature reservoirs becomes essential in order to meet the ever-increasing energy demands. As conventional recovery methods are not sufficient to fulfil the growing needs, there is an incessant demand for developing new technologies which can help in efficient tertiary recovery in old reservoirs. Petroleum biotechnology has been emerging as a branch that can provide solutions to major problems in the oil industry, including increasing oil production from marginal oil wells. The enhanced oil recovery (EOR) method comprises four methods – chemical, thermal, miscible, and immiscible gas flooding – as well as microbial interference to increase recovery of the remaining hydrocarbons trapped in reservoir rocks. Biochemically enhanced oil recovery comprises an array of blooming technologies for tertiary oil recovery methods which is eco-friendly, cost-effective, and efficient in extracting the residual oil trapped in reservoir rocks. Biochemical enhanced oil recovery (BcEOR) is based on the principle of using biochemical by-products produced by microbial species to enhance oil recovery, etc. All these technologies work on the principles of reducing viscosity, increasing permeability, modifying solid surfaces, emulsifying through adherence to hydrocarbons, and lowering interfacial tension. BcEOR technologies either employ the beneficial microorganism itself or the biochemical by-products produced by the microbial species to enhance tertiary oil recovery. This review paper discusses the chronological development of biologically enhanced oil recovery and its various mechanisms.

A review of chemical-assisted minimum miscibility pressure reduction in CO2 injection for enhanced oil recovery

Miscible CO 2 injection appears to be an important enhanced oil recovery technique for improving sweep efficiency and eliminating CO 2 -oil interfacial tension resulting in up to 10% higher oil recovery compared to immiscible flooding, in addition to the environmental benefits of reducing greenhouse gas emissions through carbon capturing utilising and storage (CCUS). Moreover, this technique could be similarly applicable to natural gas and nitrogen projects to increase oil recovery and to reduce the associated gas flaring. However, miscible displacement may not be achievable for all reservoirs, in particular, reservoirs with high temperature where high injection pressure would be needed to reach miscibility which likely exceeds the formation fracture pressure. Therefore, to further achieve reservoirs’ potential, there is a pressing need to explore a viable means to decrease the miscibility pressure, and thus expand the application envelop of miscible gas injection in reservoirs with high temperatures. In this work, we aim to provide insights into minimum miscibility pressure (MMP) reduction by adding chemicals into CO 2 phase during injection. We achieved this objective by performing a comprehensive review on chemical-assisted MMP reduction using different chemical additives (e.g., alcohols, fatty acids, surfactants) and different experimental methodologies. Previous experimental studies have shown that a fraction of chemical additives can yield up to 22% of MMP reduction in CO 2 -oil system. Based on results analysis, surfactant based chemicals were found to be more efficient compared to alcohol based chemicals in reducing the interfacial tension in the CO 2 -oil system. Based on the current experimental results, adding chemicals to improve the miscibility and reduce the MMP in the CO 2 -oil system appears to be a promising technique to increase oil recovery while reducing operating cost. Selection of the effective chemical additives may help to expand the application of miscible gas injection to shallow and high temperature reservoirs. Furthermore, our review provides an overall framework to screen potential chemical additives and an injection strategy to be used for miscible displacement in CO 2 and/or gas systems.

A New Predictive Method for CO2-Oil Minimum Miscibility Pressure

Gas injection processes are among the effective methods for enhanced oil recovery. Miscible and/or near miscible gas injection processes are among the most widely used enhanced oil recovery techniques. The successful design and implementation of a miscible gas injection project are dependent upon the accurate determination of minimum miscibility pressure (MMP), the pressure above which the displacement process becomes multiple-contact miscible. This paper presents a method to get the characteristic curve of multiple-contact. The curve can illustrate the character in the miscible and/or near miscible gas injection processes. Based on the curve, we suggest a new model to make an accurate prediction for CO2-oil MMP. Unlike the method of characteristic (MOC) theory and the mixing-cell method, which have to find the key tie lines, our method removes the need to locate the key tie lines that in many cases is hard to find a unique set. Moreover, unlike the traditional correlation, our method considers the influence of multiple-contact. The new model combines the multiple-contact process with the main factors (reservoir temperature, oil composition) affecting CO2-oil MMP. This makes it is more practical than the MOC and mixing-cell method, and more accurate than traditional correlation. The method proposed in this paper is used to predict CO2-oil MMP of 5 samples of crude oil in China. The samples come from different oil fields, and the injected gas is pure CO2. The prediction results show that, compared with the slim-tube experiment method, the prediction error of this method for CO2-oil MMP is within 2%.