Oil Recovery Factor Research Articles

ПРИЧИНЫ И АНАЛИЗ ОБВОДНЁННОСТИ ПРОДУКЦИИ НЕКОТОРЫХ МОРСКИХ МЕСТОРОЖДЕНИЙ АЗЕРБАЙДЖАНА

The results of researches of the water encroachment of some offshore fields (Neft Dashlary, Guneshli, Pirallahi, Darwin Banka, Apsheron Banka, Western Apsheron, etc.) of the Republic of Azerbaijan, most of which are at a late stage of development, have been presented. These fields are represented by weakly cemented and loose reservoirs of heterogeneous structure, in which there is an uneven fluid flow. Water breakthrough occurs through high-permeability layers, and layers with low permeability are involved in development to a less extent. Subsequent attempts to involve them in the development process cause an irrational increase in the volume of injected water, which leads to product encroachment. The type of reservoir, characterized by the presence of fracture zones, contributing to the flow of water from the aquifers to the producing wells, as well as improving their hydrodynamic connection with the injection wells, also contributes to the growth of the rate of watering. The geological and technological reasons for the water encroachment have been determined. The heterogeneity of the above mentioned deposits has been proven. It is indicated that an additional reason for the early water encroachment of production wells is the violation of the annulus tightness. Maintaining high rates of oil production is achieved by bringing in new production wells, while most of the watered wells are retired from operation without having exhausted their potential. It is proposed to carry out the measures that will ensure isolation of the most washed out zones and depleted areas of the main productive layer of the field. Methods of selective water isolation and flow diversion technologies should be carried out, first of all, in wells with an increased density of current reserves in order to obtain additional oil production and increase the oil recovery factor, as well as in wells with a high fluid flow rate.

Improving oil recovery of Eagle Ford shale samples using cryogenic and cyclic gas injection methods - An experimental study

Despite containing massive volumes of hydrocarbons, unconventional reservoirs have low recovery factors, <10% in oil reservoirs. Production from such ultra-low-permeable formations mainly depends on the flow conductivity. Any method enhances flow conductivity improves hydrocarbon-production from these reservoirs. In this study, implementing cryogenic and cyclic gas injection to improve oil recovery was investigated. Liquid nitrogen (LN2) was injected into saturated core samples from Eagle Ford formation at 82 °C reservoir temperature. Then, three cycles of nitrogen (N2) injection at four pressures (6.89, 13.79, 20.68, 27.58 MPa) were conducted, and oil recovery factor (RF) was calculated for up to 24 h of production period after each cycle. LN2 and cyclic N2 injection effects on core samples were assessed using computerized-tomography scan, porosity, permeability, and ultrasonic-velocity measurements. The results revealed that implementing LN2 and cyclic N2 techniques improves shale oil RF by up to 78%. Implementing LN2 and cycling N2 resulted in initiating new cracks and extending them inside the samples providing high-flow channels for the injected gas, promoting the oil and gas exchange through injection and production stages and utilizing pressure near minimum miscibility pressure yielding higher oil RF. Samples’ porosity, permeability, and velocities were altered after completing the treatments. Porosity increased by up to 60% and permeability significantly enhanced up to 2.4 orders of magnitude. Whilst P- and S-wave velocities reduced by up to 10% and 8%, respectively. Implementing LN2 and cyclic N2 could potentially be employed in shale oil fields to improve the oil recovery.

Study of single-phase polymer-alkaline-microemulsion flooding for enhancing oil recovery in sandstone reservoirs

Enhanced oil recovery methods (EOR) are designed to increase reservoir productivity by facilitating oil displacement in the porous media. Due to its physicochemical properties capable of reducing the interfacial tension and inverting rock wettability, microemulsion flooding has been studied as a chemical EOR method. In this work, we studied the injection of polymer, surfactant, and alkali as single microemulsion media. A microemulsion formulation was selected with high water content and a composition of 1.5% of active matter, 0.05% of oil phase (OP), and 98.39% of aqueous phase (AP) prepared with 1.5% of Na2CO3 and 0.06% of the polymer. The systems obtained were characterized according to droplet diameter, pH, surface tension, and viscosity. We studied the rock-fluid interaction mechanism, evaluating the reservoir rock's wettability before and after contact with the microemulsion in a Botucatu sandstone rock. The microemulsions studied promoted a significant reduction in surface tension and changed the sandstone wettability from oil to water-wet. Coreflooding experiment results proved the potential of microemulsions prepared with alkali and polymer in the EOR process, achieving up to 97% of the oil recovery factor.

A laboratory approach to enhance oil recovery factor in a low permeable reservoir by active carbonated water injection

In this paper, different injectivity scenarios were experimentally investigated in a coreflooding system to observe the efficiency of each method in laboratory conditions. Surfactant flooding, CO2 injection, carbonated water injection (CWI), active carbonated water injection (ACWI), after water flooding were investigated through the coreflooding system. First, it is necessary to optimize the surfactant concentration and then use it in ACWI injection. To do this, linear alkylbenzene sulfonic acid (LABSA) was used as a cationic surfactant at different concentrations. It was observed that 0.6 PV concentration of LABSA had an optimum result as increasing the surfactant concentration would not be significant enough. The increase of active carbonated water has increased oil recovery as it has the maximum oil recovery factor of 64% with the carbonated water of 1 PV that there is more gas transfer to the oil phase. Therefore, surfactant addition would be an applicable chemical agent to reduce the interfacial tension and carbonated water volume required in the injectivity scenarios.

Numerical Investigation of Controllable Parameters Effect on Nanofluid Flooding in a Random Pore Generated Porous Medium

This study simulates the enhanced oil recovery process using nanofluids into a microporous medium. To obtain the optimum values that affect this process, design experiments with the general factorial method was performed. Four parameters included type of nanoparticles and the base fluids, diameter, and volume fraction of nanoparticle were considered. The porous medium was created with the commercial grid generation tool and Fluent software was used to solve the governing equations. Comparison of numerical results with the experimental data illustrates that they are in good agreement. In addition, results show that clay nanoparticles with formation water have the greatest impact on the oil recovery factor compared to other nanofluids. Also the nanofluid with higher amounts of nanoparticles in the base fluid and smaller diameter have better performance in improving the oil recovery factor. Therefore, for having the maximum oil recovery factor, the best combination of parameters is clay nanoparticles with 2 nm diameter and 5 vol. % in formation water.

Joint Optimization of Well Completions and Controls for CO2 Use and Storage

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 200316, “Joint Optimization of Well Completions and Controls for CO2 Enhanced Oil Recovery and Storage,” by Bailian Chen, SPE, and Rajesh Pawar, Los Alamos National Laboratory, prepared for the 2020 SPE Improved Oil Recovery Conference, originally scheduled to be held in Tulsa 18–22 April. The paper has not been peer reviewed. Carbon dioxide (CO2) storage through CO2 enhanced oil recovery (EOR) has been considered an option for larger-scale deployment of CO2 storage because of the economic benefits of oil recovery, 45Q tax credits, and the use of existing infrastructure. The complete paper investigates how optimal reservoir management and operation strategies can be used to optimize both CO2 storage and oil recovery. Results of the authors’ study showed that joint optimization of well completions and well controls can achieve a higher final net present value (NPV) than that obtained from the optimization of well controls only. Introduction In CO2 EOR associated with storage processes, poorly designed well-operating conditions or completions can lead to low oil recovery factors and suboptimal CO2 storage. Co-optimization of oil production and CO2 storage has been recognized as a feasible technique to maximize benefit in terms of oil production and CO2 storage tax credit. To the best of the authors’ knowledge, settings for well completions have not been considered as optimization variables in a CO2 EOR and storage co-optimization process. The objective of this study is to conduct joint optimization of well completions and controls [well rates or bottomhole pressures (BHP)] that maximize life-cycle NPV in CO2 EOR and storage processes and demonstrate the superiority of joint optimization over well-control-only optimization. Optimization Problem In this study, the optimization problem considered is the joint optimization of well completions and well controls for a CO2 EOR and storage process. The mathematical process behind this determination is detailed in the complete paper. The optimization problem was focused on jointly estimating the well completions (i.e., fraction of injection/production well perforations in each reservoir layer) and CO2 injection and oil-production controls that maximize NPV in a CO2 EOR and storage operation. The authors used a newly developed stochastic simplex approximate gradient algorithm to solve the optimization problem. The performance of the joint optimization approach was compared with the performance of the well-control-only optimization approach. In addition, the performance of the co-optimization of CO2 storage and oil-recovery approach was compared with that of the maximization of only-CO2-storage and only-oil-recovery approaches.

Prediction of top water flow rate to SAGD steam chamber and its impact on thermal efficiency

The Guantao Formation in the Block Du 84 of the Liaohe Oilfield of Northeastern China is a super heavy oil reservoir surrounded by top water, side and bottom water. Commercial development started in 1999 using vertical well Cyclic Steam Stimulation (CSS), with anticipated oil recovery factor of less than 25%. To improve the ultimate oil recovery, a pilot test of SAGD as a follow-up to CSS began in 2005 using a combination of infill horizontal wells with existing vertical wells; and the commercial expansion began in 2008 as a result of the encouraging results from pilot test. The current recovery factor over the entire development area has exceeded 45% of OOIP, with the pilot test area exceeding 68% of OOIP, and the ultimate recovery factor is predicted to exceed 70%. As the steam chamber becomes more mature and continues expanding upward, the risk of communication with the top water increases. Due to high pressure (>6.0 MPa) in the top water layer, it is not practical to balance the operating pressure in the steam chamber under the current economic conditions. The early forecasting of top water flow rates is important to assess its potential impact on SAGD performance and to formulate operating strategies for the late stage of SAGD development. In this paper, a theoretical model for predicting flow rate of top water to the SAGD chamber is established based on the incorporation of fluid flow and heat transfer mechanisms in porous media in the reservoir (barrier layer) between the steam chamber and the top water. The influence of barrier layer thickness, permeability, crude oil viscosity distribution and operating pressures in the steam chamber on the flow rate of the top water are studied. The flow of the top water into the steam chamber will lower oil to steam ratio (OSR) and the recovery process may become uneconomic when top water flow rate exceeds the current steam injection rate per well pair. The presence of high-viscosity “asphalt shell” layers near the bottom of the top water has limited mitigation effect on the flow of the top water. Under current operating conditions and 3.0 MPa pressure differential between the top water layer and steam chamber, 10 m of minimum thickness of barrier layer should be maintained to effectively mitigate the risk from inflow of top water.

Modeling Oil Recovery in Brazilian Carbonate Rock by Engineered Water Injection Using Numerical Simulation

Waterflooding remains the most commonly used method to improve oil recovery. Although the injected brine type is mainly dependent on its availability, few of its characteristics can be controlled during project design. Published laboratory work indicates that the adjustment of injected brine composition can cause an increase in oil production by wettability alteration. This research objective is to propose a novel four-step framework for modeling improved oil recovery by Engineered Water Injection from laboratory to numerical simulation for carbonate formations. We use a geochemical-based model that estimates contact angles to predict wettability alteration. The steps are (1) screening criteria, (2) geochemical evaluation, (3) wettability alteration modeling, and (4) coreflood history-match. We validate our framework by conducting history-match simulations of Brazilian Pre-Salt corefloods. Incremental oil recovery factors are between 5 to 11%, consistent with those reported during experiments. The reduction in residual oil saturation varied from 3 to 5%. This work is a new systematic procedure to model oil recovery using a comprehensive approach that is fundamental to understanding the underlying wettability alteration mechanisms by Engineered Water Injection.

An Improved Multicomponent Diffusion Model for Compositional Simulation of Fractured Unconventional Reservoirs

Summary Most simulators currently use the advection/diffusion model (ADM), where the total flux comprises Darcian advection and Fickian diffusion. However, significant errors can arise, especially for modeling diffusion processes in fractured unconventional reservoirs, if diffusion is modeled by the conventional Fick’s law using molar concentration. Hence, we propose an improved multicomponent diffusion model for fractured reservoirs to better quantify the multiphase multicomponent transport across the fracture/matrix interface. We first give a modified formulation of the Maxwell-Stefan (MS) equation to model the multicomponent diffusion driven by the chemical potential gradients. A physics-based modification is proposed for the ADM in fractured reservoirs, where fracture, matrix, and their interface are represented by three different yet interconnected flow domains to honor the flux continuity at the fracture/matrix interface. The added interface using a more representative fluid saturation and composition of the interface can hence better capture the transient mass fluxes between fracture and matrix. The proposed approach is also implemented in an in-house compositional simulator. The multicomponent diffusion model is validated with both intraphase and interphase diffusion experiments. Then, the improved model for fracture/matrix interaction is compared with a fine-grid model. The proposed multiple interacting continua (MINC) model with three continua (MINC3) can better match the fine-grid model’s result than the double-porosity (DP) model, which only obtains a fair match at an early time. Then, we simulate a gas huff ‘n’ puff (HnP) well in the Permian Basin to investigate the effect of diffusion within the fractured tight oil reservoir. The simulation reveals that diffusion has a minor effect on the performance of depletion when oil is the dominant phase. For gas HnP, the simulation neglecting diffusion will underestimate the oil recovery factor (RF) but overestimate the gas rate. The DP approach tends to overestimate the RF of heavy components but leads to a similar cumulative oil RF compared with MINC3. With the diffusion included in the simulation, gas HnP performance becomes more sensitive to the soaking time than the model without diffusion. Although increasing the soaking time will lead to a higher RF after considering diffusion, the incremental oil is not sufficiently large to justify a prolonged soaking time.

Numerical study of the mechanisms of enhanced oil recovery using nanosuspensions

The results of the numerical study of oil recovery enhancement using nanosuspension are presented. The research was carried out using the volume of fluid method (VOF) for a 2D microporous core model. Experimentally measured values of interfacial tension (IFT) and the contact angle (CA) were used for numerical modeling. An aqueous suspension with silicon oxide nanoparticles (5 nm) is used. It was shown that when 1 wt% of nanoparticles are added to the displacing liquid, its density increases by about 1%, the viscosity increases by 10%, the IFT decreases by 10%, and the contact angle increases from 70 to 145 $$^\circ $$ . The results of numerical study showed that the injection of nanoparticles has a significant effect on the displacement front movement in the microporous model. It has been shown that the nanosuspension can increase the oil recovery factor (ORF) almost twice as compared to water. To clarify the mechanisms of increasing the oil recovery during the reservoir flooding with nanofluid, a systematic study of factors affecting the displacement process efficiency was carried out. Viscosity, interfacial tension and the wetting angle of the displacing fluid were considered as such factors. As a result of systematic research, it has been shown that the main factor affecting the increase in the oil recovery flooding of nanosuspensions is a variation of wettability.

A qualitative study of the impact of random shale barriers on SAGD performance using data analytics and machine learning

Shale barriers are common in all types of oil and gas reservoirs. Previous works on characterizing the impact of random shales are limited. Although for a gravity-based recovery method such as steam-assisted gravity drainage (SAGD), these shale barriers prove to be a major hurdle in production rate and ultimate oil recovery. Apart from obstructing the oil drainage path, shale barriers may also contribute to the additional heat losses. Hence characterizing these shale barriers is of importance to understand the magnitude of their impact on oil recovery. In this paper, first, we describe a procedure to construct the base 2D reservoir model and then populate it log-normally with various scenarios of random shales based on the mean and standard deviation. Unique features are extracted to parameterize these random shales. Next, the impact of reservoir heterogeneity on the recovery factor is described qualitatively using these shale features. Second, we prepare a non-linear model using a machine learning algorithm for predicting oil recovery factor using a synthetic dataset. We demonstrate that the machine learning approach can predict the oil recovery factor with reasonable accuracy compared with thermal numerical reservoir simulation results. The model resulted in an R2 value of 0.95 and RMSE of 5.06. Considering the complexity of characterization of randomly distributed shales, this is a considerable accuracy from a model trained on 226 simulation data sets. The approach described in this paper can be used as a technique to characterize the impact of randomly distributed shales. The predictive model may also be utilized to run a large set of sensitivity, which can prove effective for making a real-time decision. These techniques can be further advanced with a larger set of training data, including a variety of dynamic and static reservoir properties.

Experimental Investigation on the Characteristic Mobilization and Remaining Oil Distribution under CO2 Huff-n-Puff of Chang 7 Continental Shale Oil

The Chang 7 continental shale oil reservoir is tight. The recovery factor is extremely low, the remaining oil is very high, and injecting water to improve oil recovery effectiveness is too hard. Therefore, in this paper, physical simulation experiments of CO2 huff-n-puff shale oil and NMR tests were conducted to study the cycle numbers and permeability on the recovery degree, as well as the characteristics of shale oil mobilization and the remaining oil micro distribution. The results showed that the cumulative oil recovery factors (ORFs) gradually increased in the natural logarithmic form, the single cycle ORFs decreased rapidly in exponential form with the huff-n-puff cycle number, and the biggest economic cycle numbers were between approximately 3 and 5. Furthermore, the higher the permeability, the higher the ORF, but the difference of ORF decreased between the two experimental samples with the cycles. In addition, the gap of production and recovery degree was large between the different scale pores, the ORF of macropores was 6–8 times that of micropores, and the final remaining oil was mainly distributed in the micropores, accounting for 82.29% of the total amount; meanwhile, the macropores comprised less than 0.5%. In the process of huff-n-puff, CO2 flowed into macropores, mesopores, and smallpores under the pressure differential effect, but a small amount of CO2 slowly diffused into micropores, resulting in the ORF of the former with more free oil being higher and the ORF of micropores with more adsorbed oil being lower. Therefore, promoting a better contact and reaction between CO2 and shale oil of micropores is one of the key ways to effectively develop the Chang 7 continental shale oil and enhance oil recovery.

Polymer-Nanosilica-assisted to evaluate oil recovery performances in sandstone reservoirs

Implementation of Nanosilica particles in chemical flooding processes would be of interest for petroleum industries as nanoparticles can improve the polymer performances during oil recovery processes. In this paper, three different injectivity scenario of polymer–Nanosilica, Polymer solution, and water flooding were experimentally investigated to measure oil recovery factor, contact angle, and interfacial tension. Oil recovery factor for polymer–Nanosilica, polymer, and water flooding is 65%, 55%, and 50% respectively. Water flooding was performed until 2 PV and it did not continue as there is no progress in recovery factor in this scenario. After that, polymer solution was injected until 5 PV to reach a plateau. Krw has witnessed its minimum value of 0.3 and 0.15 for water–polymer–Nanosilica and polymer–Nanosilica respectively. This issue has a capillary forces decrease, which would be a proper reason for oil recovery enhancement. Secondary water drive mechanism would be an increasing point on the Krw for both scenarios. Regarding the increase of surface hydrophilicity in the presence of Nanosilica–polymer, contact angle has been decreased dramatically in the low concentration of Nanosilica. Nanosilica addition into water and polymer has caused to reduce the IFT by the increase of Nanosilica concentration. This reduction corresponds to the decrease of Gibbs energy in the presence of Nanosilica particles.

Numerical Simulation of Low Salinity Water Flooding on Core Samples for an Oil Reservoir in the Nam Con Son Basin, Vietnam

Low-salinity water flooding (LSWF) is environment-friendly and operates similarly to conventional waterflooding without the need for synthetic chemical materials. The application of LSWF makes sense in Vietnam as HC production has steadily declined since 2002, and the majority of main oil fields have become near mature and mature fields. In the next years, Enhanced Oil Recovery (EOR) should be a top priority for Petro Vietnam to boost its oil production, for which the key issue is how to select a suitable EOR technology. In this study, LSWF of the Lower Miocene sand using low salinity water from Lower Oligocene sand was investigated. Previously at the Ruby field in the Cuu Long Basin, an LSWF feasibility study was carried out based on a conventional core flooding experiment, which is time-consuming and costly. This study targets the Chim Sao field in the Nam Con Son Basin, for which a cheaper and faster assessing method is required. As a result, a numerical code written in Matlab was developed and successfully validated with the core flooding experiment results obtained at the Ruby field. The LSWF simulation was conducted using the multiple ion-exchange mechanisms (MIE), and the results obtained showed an increase in the oil recovery factor by 2.19% for the Lower Miocene Sand. Another important outcome of this study is the innovative proposal and successful simulation to use the abundant low salinity water from the underlying Lower Oligocene sand as a natural LSW source to inject into the Lower Miocene oil reservoir that can be a decisive factor to help apply LSWF in practice on a wide scale not only for Chim Sao but also other similar oil fields in southern offshore Vietnam.

Numerical investigation of single- and two-phase flow in porous media with a bifurcated fracture

Considering that fractures arising from fracturing systems have bifurcation characteristics, mathematical models for single- and two-phase flow in porous media with a bifurcated fracture (BFPM) were established. The phase-field method was adopted to trace the oil–water interface, and the influence of fracture morphology, boundary conditions, gravity, and wettability on imbibition in BFPM was discussed. The results are as follows: (1) during single-phase flow in BFPM, the velocity in the bifurcated fracture was several orders of magnitude greater than that in the matrix. (2) Imbibition in BFPM includes countercurrent imbibition and the combination of co-current and countercurrent imbibition. The bifurcated fracture produces an increase in matrix pores that participate in imbibition, thus increasing the oil recovery factor by approximately 30% during simulation. (3) Closing an outlet of the bifurcated fracture has minimal effect on imbibition during the early stage (approximately the first 6 s) and an inhibitory effect during the middle and late stages (after 6 s), which leads to a decrease in oil recovery factor. (4) When the surface tension value is low (0.1 and 1 mN/m), disregarding the effect of gravity during imbibition results in an overestimated oil recovery factor value, while a large surface tension value (20 and 25 mN/m) produces the opposite effect. (5) Similar to the laws followed in porous media with pure pores and a single fracture, improving BFPM wettability increases the oil recovery factor value. This study can provide guidance for the production of low-permeability reservoirs.

Technology Focus: Intelligent Operations (May 2021)

The last year has seen people in many sectors unexpectedly confronting a new challenge—working remotely. Even before this, our industry has been trying to operate fields remotely (either partially or fully) and make operations smarter and more automated. Key drivers are to improve safety in operations, maximize production, and make operations more efficient. These efforts have been enabled by the rapidly changing technology landscape—in sophisticated acquisition and analysis of data and increased connectivity (from both fiber-optic and cellular networks). It also has been accelerated by the push across the industry to digitalize. We now acquire, process, and analyze much more detailed operations data and use the analysis to actively control wells and operations. This feature highlights recently presented papers that cover the following topics. How Digital Transformation Has Progressed. Paper OTC 30794 discusses similar efforts in other sectors, including marine/ship building and auto manufacturing. Paper SPE 200728 discusses use of a digital twin to improve operational efficiency in a mature brownfield setting (Brage Field in the Norwegian North Sea). Paper OTC 30488 describes extensible and scalable remote monitoring and control using a digital decision assistant. How Technology Has Enabled Data Acquisition and Analysis From Relatively New Sources [e.g., Distributed Temperature Sensing (DTS) or Distributed Acoustic Sensing]. Paper SPE 200826 describes seven DTS applications from around the world that monitor well integrity, stimulation, and injection profiles and identify gas, water, or sand production. Paper OTC 30442 and other papers from the Bokor field in Malaysia describe DTS data from fiber-optic cable behind casing in wells with smart completions. Papers IPTC 19574 and SPE 202349 show how pressure telemetry can enable wireless control of completions. The Path to Fully Remotely Operated Fields. Paper SPE 203461 discusses the design and execution of digitalization and remote operations in a new development area with high hydrogen sulfide (the Mender satellite field in the UAE). Paper SPE 202667 describes the applications for multiple autonomous robots controlled remotely. Digital transformation of work flows and operations clearly is happening across the industry and adding significant value. The next frontier on the digital transformation and Industry 4.0 journey might be to achieve step-change increases in oil and gas recovery factors. Recommended additional reading at OnePetro: www.onepetro.org. SPE 200728 - The Digitalization Journey of the Brage Digital Twin by Peter Kronberger, Wintershall, et al. OTC 30442 - Innovative Solution for IWAG Injection Monitoring Using Fiber-Optic Cable Cemented Behind Casing in an Intelligent Well: A First in Malaysia by Nur Faizah P. Mosar, Schlumberger, et al. SPE 202667 - Operations Room: A Key Component for Upscaling Robotic Solutions on Site by Jean-Michel Munoz, Total, et al. OTC 30488 - Machine-Learning-Enabled Digital Decision Assistant for Remote Operations by Vitor Alves da Cruz Mazzi, Intelie, et al. IPTC 19574 - Research and Application of Downhole Remote Wireless Control Technology Based on Gas Pressure Wave in Tubing by Mingge He, China National Petroleum Corporation, et al. SPE 202349 - Pressure Wave Downhole Communication Technique for Smart Zonal Water Injection by Quanbin Wang, China National Petroleum Corporation, et al.

Dynamic reservoir sand characterization of an oil field in the Niger Delta from seismic and well log data

Many oil fields within the Niger Delta have been abandoned after serving their estimated life time largely due to large uncertainties and risks associated with many subsurface complexities and often limited and/or inconsistent surveillance data coupled with the convectional static characterization of the reservoir bodies as is the case of the X- oil Field, south eastern onshore, Nigeria. This research presents a pragmatic approach of integrated dynamic reservoir modelling with uncertainty management techniques, which resulted in robust productivity of the abandoned oil field. The objective is to run and improve comprehensive sensitivity analysis of petrophysical properties in the reservoir, develop PVT analysis, and predict acceptable original oil in place (OOIP), comprehensive production history and expected cumulative oil recovery factor (RF). Integrated dynamic reservoir modelling of static interpreted reservoirs of two vertically stacked reservoirs (A and B) was done. The analysis identified reservoir A with an OWC at 5520 ft with thickness of about 300 ft and STOIIP of 59 MMSTB has an underlying reservoir B with OWC at 6100 ft with thickness of about 300 ft and STOIIP of 21 MMSTB. Average permeabilities and porosities of both reservoirs range from 2.54 to 1115.2 md and 0.2 to 0.33 respectively, with estimated cumulative oil production of 46.62 MMSTB at 55% RF in reservoir A and 17.21 MMSTB at 48% RF in reservoir B. This was estimated to correspond to maximum cumulative oil production of 40 MMSTB by August 2020 indicating that the overall recovery from the field could potentially be increase by 6% from drilling infill wells with drainage targets. Production data analysis indicates that the recovery factors and well recoverable volumes are highly correlated to average net oil pay. The correlations may be used for reserve quality control. It is recommended that improved quality of data couple with integration of statics with dynamic modelling should be a priority to reduce uncertainties and solve problems in situ in field operations leading to increase in oil recovery during activation of abandoned oil field.

On the application of surfactant and water alternating gas (SAG/WAG) injection to improve oil recovery in tight reservoirs

Tight reservoirs are considered one of the unconventional hydrocarbon reservoirs with low permeability and porosity, directly affecting the oil production rate rather than conventional reservoirs. Thereby, optimum enhanced oil recovery methods would help petroleum industries produce more oil volumes from these reservoirs. In this study, different chemical and thermal enhanced oil recoveries methods such as surfactant alternating gas (SAG), water alternating gas (WAG), surfactant and foam flooding, and carbon dioxide (continuous and cyclic) were experimentally investigated to measure oil recovery factor. According to the results of this study, 3.5% of surfactant concentration, 0.15 PV of surfactant slug size, and 0.75 PV was selected as the total surfactant injection volume was selected as the optimum concentration for the injectivity performances. SAG scenario provided the highest oil recovery factor among all injectivity scenarios. It is about 54% that indicated the best efficiency of enhanced oil recovery methods in tight reservoirs rather than conventional recovery methods. The second highest oil recovery factor is dedicated to the WAG injectivity scenario regarding the feasibility of CO2 phase through porous media. It is about 46%. Moreover, due to the -gas phase in WAG and SAG, water cut had fluctuated as the water and gas had been alternatively injected into the core samples.

Hybrid Application of Nanoparticles and Polymer in Enhanced Oil Recovery Processes.

Nowadays, the addition of nanoparticles to polymer solutions would be of interest; however, the feasible property of nanoparticles and their impact on oil recovery has not been investigated in more detail. This study investigates the rheology and capillary forces (interfacial tension and contact angle) of nanoparticles in the polymer performances during oil recovery processes. Thereby, a sequential injection of water, polymer, and nanoparticles; Nanosilica (SiO2) and nano-aluminium oxide (Al2O3) was performed to measure the oil recovery factor. Retention decrease, capillary forces reduction, and polymer viscoelastic behavior increase have caused improved oil recovery due to the feasible mobility ratio of polymer–nanoparticle in fluid loss. The oil recovery factor for polymer flooding, polymer–Al2O3, and polymer–SiO2 is 58%, 63%, and 67%, respectively. Thereby, polymer–SiO2 flooding would provide better oil recovery than other scenarios that reduce the capillary force due to the structural disjoining pressure. According to the relative permeability curves, residual oil saturation (Sor) and water relative permeability (Krw) are 29% and 0.3%, respectively, for polymer solution; however, for the polymer–nanoparticle solution, Sor and Krw are 12% and 0.005%, respectively. Polymer treatment caused a dramatic decrease, rather than the water treatment effect on the contact angle. The minimum contact angle for water and polymer treatment are about 21 and 29, respectively. The contact angle decrease for polymer treatment in the presence of nanoparticles related to the surface hydrophilicity increase. Therefore, after 2000 mg L−1 of SiO2 concentration, there are no significant changes in contact angle.

Pore-Scale Imaging and Analysis of Wettability Order, Trapping and Displacement in Three-Phase Flow in Porous Media with Various Wettabilities

Three-phase flow in porous media is encountered in many applications including subsurface carbon dioxide storage, enhanced oil recovery, groundwater remediation and the design of microfluidic devices. However, the pore-scale physics that controls three-phase flow under capillary dominated conditions is still not fully understood. Recent advances in three-dimensional pore-scale imaging have provided new insights into three-phase flow. Based on these findings, this paper describes the key pore-scale processes that control flow and trapping in a three-phase system, namely wettability order, spreading and wetting layers, and double/multiple displacement events. We show that in a porous medium containing water, oil and gas, the behaviour is controlled by wettability, which can either be water-wet, weakly oil-wet or strongly oil-wet, and by gas–oil miscibility. We provide evidence that, for the same wettability state, the three-phase pore-scale events are different under near-miscible conditions—where the gas–oil interfacial tension is ≤ 1 mN/m—compared to immiscible conditions. In a water-wet system, at immiscible conditions, water is the most-wetting phase residing in the corners of the pore space, gas is the most non-wetting phase occupying the centres, while oil is the intermediate-wet phase spreading in layers sandwiched between water and gas. This fluid configuration allows for double capillary trapping, which can result in more gas trapping than for two-phase flow. At near-miscible conditions, oil and gas appear to become neutrally wetting to each other, preventing oil from spreading in layers; instead, gas and oil compete to occupy the centre of the larger pores, while water remains connected in wetting layers in the corners. This allows for the rapid production of oil since it is no longer confined to movement in thin layers. In a weakly oil-wet system, at immiscible conditions, the wettability order is oil–water–gas, from most to least wetting, promoting capillary trapping of gas in the pore centres by oil and water during water-alternating-gas injection. This wettability order is altered under near-miscible conditions as gas becomes the intermediate-wet phase, spreading in layers between water in the centres and oil in the corners. This fluid configuration allows for a high oil recovery factor while restricting gas flow in the reservoir. Moreover, we show evidence of the predicted, but hitherto not reported, wettability order in strongly oil-wet systems at immiscible conditions, oil–gas–water, from most to least wetting. At these conditions, gas progresses through the pore space in disconnected clusters by double and multiple displacements; therefore, the injection of large amounts of water to disconnect the gas phase is unnecessary. We place the analysis in a practical context by discussing implications for carbon dioxide storage combined with enhanced oil recovery before suggesting topics for future work.