Oil Production Water Research Articles

Changes in the Properties of Soils Contaminated with Oil Production Water Before and Af ter Treatment with CaO

In the Mexican southeast, hydrocarbon spills and their residues af fect various agricultural sites. A specific case is spills of oil production or congenital waters that cause soil salinization. When soil is contaminated, restorations are regularly carried out based on regulatory limits, but many regions still do not consider the pedological classification, so restorations are not entirely ef fective and, in the case of agricultural soils, reduce your productivity. For these reasons, this study evaluated the cation exchange with CaO applied to four soils contaminated with congenital waters and determined if there are dif ferences in the treatment behavior according to the properties of each soil. It will be found that sandy soils require less treatment time, but have greater ef fects on their properties compared to clay soils, mainly in field capacity, pH, and porosity. Furthermore, it was found that contaminant removal times vary with respect to the type of soil and that this could be related to the amount and type of clay. In the case of congenital water spills, clay soils show a greater increase in electrical conductivity (EC) compared to sandy soils. When remediated with CaO, clay soils needed longer treatment times to reduce EC, but presented fewer changes in their physical and chemical properties. In addition, it was found that, although washing with drinking water is carried out, the treatment with CaO adds alkalinity to the soils, so they must be managed according to the crop to be developed. It is concluded that soils have dif ferent physical and chemical properties, this influences the response they have to an external agent, both when contaminated and when remediated.

Effect of the oil content on green hydrogen production from produced water using carbon quantum dots as a disruptive nanolectrolyte

Considering that high-purity fresh water is employed in the green production of hydrogen via commercial water electrolyzers and that over 80% of the global population faces significant water safety risks, it is essential to explore alternative water sources. One such alternative is the use of produced water from oil extraction processes. Hence, the main objective of this study is to evaluate the effect of the oil content of oilfield production water on the production of green hydrogen by electrolysis in the presence of carbon quantum dots (CQDs). For this purpose, various electrochemical techniques, such as linear sweep voltammetry (LSV), cyclic voltammetry (CV), and potentiometry, were used to identify the effect of crude oil during hydrogen production. Thermogravimetric analysis (TGA), mass spectrometry (MS), and Fourier-transform infrared spectroscopy (FTIR) were employed to discern the adsorption of crude oil onto the electrodes, quantify the gas fractions generated during the process and identify the functional groups present after the procedure, respectively. Also, optical microscopy was employed to follow the droplet size in the emulsion. The results show that using CQDs affects the Faradaic efficiency, which increases from 77% to 83% with the incorporation of CQDs. In the presence of CQDs, the effects generated by the presence of the oil are inhibited at low oil concentrations.On the contrary, hydrogen production increases by 10.0% (0.1 mL/min) with a faradaic efficiency of 83% and a half-cell efficiency of 41%, compared to the record obtained with the maximum concentration of emulsified crude oil (400 mg/L). The mean size of the initial emulsion droplets was 3.4 μm. At the end of the test, there was evidence of complete breakage of the emulsion due to the effect of the applied electric field. No evidence of adsorption of crude oil on graphite electrodes during electrolysis is observed based on the tests. It has been shown that green hydrogen production from crude oil production water is feasible due to the proposed disruptive electrolytes in the produced water, which inhibit the effect of oil content in the O/W emulsion. This allows the implementation of a new green energy production initiative aligned with the global goal of achieving net zero emissions (NZE) by 2050. The current investigation presents a prospective alternative for harnessing the 18 kW electrical energy potential employed within emulsion-breaking processes within a Colombian field for treatment of around 1000 bpd. This alternative offers a theoretical potential for hydrogen production, approximating 7.36 kW, thus representing a promising opportunity for practical field deployment.

Microbial recovery of oils from surface oil and gas production water by reducing surface and interfacial tensions at the petrochad (mangara) limited field in badila

Demulsifiers such as VX champion, BAD-106 and others injected into the Petrochad(Mangara) Limited field between 2014 and 2023 only recovered 43,501,365 barrels out of a forecast of 91,250,000 barrels, or 42.48%. The mean surface and interfacial tension related to this recovery is 56.42 and 59.8 mN/m respectively. The inadequacy of this recovery is linked to the ineffectiveness of demulsifiers in reducing the surface and interfacial tensions between the phases and releasing the oils sufficiently. The biosurfactants produced by isolates RPG14, RPG18 and RPG20 isolated and obtained by screening tests are very active in lowering surface (23.70, 0.5±, 22.45, 0.5± and 22.75, 0.5 mN/m) and interfacial (14.35, 0.5, 15.35, 0.5 and 15.45, 0.5 mN/m) tensions. This reduction in tensions made it possible to recover respectively 86518548.36 barrels or a percentage of 84.49% for the RPG14 isolate, 88126219.86 barrels or 86.06% for the RPG18 isolate and 87740542.5 barrels or 85.68% for the RPG20 isolate.

Mechanistic Insights into a Novel Controllable Phase-Transition Polymer for Enhanced Oil Recovery in Mature Waterflooding Reservoirs.

Expanding swept volume technology via continuous-phase polymer solution and dispersed-phase particle gel is an important technique to increase oil production and control water production in mature waterflooding reservoirs. However, problems such as the low viscosity retention rate, deep migration, and weak mobility control of conventional polymers, and the contradiction between migration distance of particle gel and plugging strength, restrict the long-term effectiveness of oil displacement agents and the in-depth sweep efficiency expanding capability in reservoirs. Combined with the technical advantages of polymer and particle gel, a novel controllable phase-transition polymer was developed and systematically studied to gain mechanistic insights into enhanced oil recovery for mature waterflooding reservoirs. To reveal the phase-transition mechanism, the molecular structure, morphology, and rheological properties of the controllable phase-transition polymer were characterized before and after phase transition. The propagation behavior of the controllable phase-transition polymer in porous media was studied by conducting long core flow experiments. Two-dimensional micro visualization and parallel core flooding experiments were performed to investigate the EOR mechanism from porous media to pore level. Results show that the controllable phase-transition polymer could change phase from dispersed-phase particle gel to continuous-phase solution with the prolongation of ageing time. The controllable phase-transition polymer exhibited phase-transition behavior and good propagation capability in porous media. The results of micro visualization flooding experiments showed that the incremental oil recovery of the controllable phase-transition polymer was highest when a particle gel and polymer solution coexisted, followed by a pure continuous-phase polymer solution and pure dispersed-phase particle gel suspension. The recovery rate of the novel controllable phase-transition polymer was 27.2% after waterflooding, which was 8.9% higher than that of conventional polymer, providing a promising candidate for oilfield application.

Simulation study of water and gas injection process into the Azadegan reservoir for enhanced oil recovery

AbstractIt is necessary to improve oil production from reservoirs. Various methods have been proposed to increase oil extraction from reservoir. Each method has specific challenges. In this research, the effect of water and gas injection in to Azadegan reservoir has been analyzed. Azadegan oil field is located south of Iran. In this study, water, immiscible gas and water alternating gas injected to reservoir and its effect on enhanced oil recovery have been investigated. Finally, a comparison between results of methods is provided. Results show that effective method for enhanced oil recovery is immiscible gas injection with 46% oil production efficiency and water alternating gas injection with 36% oil production efficiency. This study shows that oil production efficiency can be increased if duration of gas injection is increased. This study shows, increasing viscosity of water in water alternating gas scenario did not improve the production of Azadegan reservoir.

Carbonated Smart Water Injection for Optimized Oil Recovery in Chalk at High Temperature

Finding cost-efficient ways of increasing oil production with a low carbon footprint is the new challenge for the petroleum industry that wants to meet the net-zero emission goals by 2050. Smart water injection is an EOR process that increases oil production and delays water breakthrough by wettability alteration. Seawater is a smart water in chalk reservoirs, being especially effective at high temperatures. Different studies have shown that the effectiveness of seawater can be further improved by modifying the ion composition before injection. Carbonated water (CW) has been proposed as a potential EOR fluid. In addition to producing extra oil, the reduction of greenhouse gas (CO2) in the atmosphere can be achieved by using carbonated smart water as an injection fluid. The main mechanism behind increased oil recovery by injecting carbonated water is believed to be oil viscosity reduction and swelling, as the CO2 is transferred from the aqueous phase to the oil phase. Wettability alteration has also been proposed as a possible mechanism, and this hypothesis is further investigated in this study along with other proposed mechanisms. Stevns Klint outcrop chalk was used in this study, this material is recognized as an excellent analogue for North Sea chalk reservoirs. Optimized oil recovery by carbonated water in chalk was investigated at a high temperature (130°C) by flooding carbonated formation water (CFW) and carbonated seawater (CSW), to be compared with high saline formation water (FW) and seawater (SW) flooding. The oil/brine/rock/CO2 interactions were tracked by measuring the pH of the produced water (PW) and by identifying any mineralogical changes by SEM (Scanning Electron Microscope) and EDX (Energy Dispersive X-Ray) analyses. The solubility of CO2 in different brines was measured and compared with simulation data performed by PHREEQC. The diffusion of CO2 from the aqueous phase to the oil phase was analysed to check if enough CO2 can be diffused from the carbonated water into the oil phase. By flooding CSW in both secondary and tertiary modes, a slight increase in the oil recovery was observed and was found to be the best performing brine. The oil recovery was also slightly increased using CFW in tertiary mode after FW which does not behave like smart water for carbonates. The solubility of CO2 was low and increased by increasing pressure and decreasing brine salinity. The acidity of CW did not increase by increasing pressure. No changes in pore surface minerals were observed after CW flooding, confirming limited mineral dissolution. A mass transfer of CO2 from the brine phase to the oil phase was confirmed in the experimental work, but a significant amount of CO2 remained in the brine phase. The main mechanism behind this extra oil observed using CW is most likely not linked to oil swelling and viscosity reduction or mineral dissolution which could affect the porosity and the permeability of the rock system. Wettability alteration is a more likely explanation but needs to be looked further into for confirmation.

Genome sequence of Pseudomonas aeruginosa PA1-Petro—A role model of environmental adaptation and a potential biotechnological tool

Pseudomonas aeruginosa is a ubiquitous microorganism, capable of colonizing a wide range of habitats due to its metabolic versatility and wide adaptability to different conditions. Industrial and environmental research involving petroleum microbiology play a pivotal role in controlling many technical, operational, and environmental issues. P. aeruginosa PA1-Petro strain was isolated from oil production water in Northeastern Brazil. Herein we report the genomic sequencing and annotation of PA1-Petro, and a comparative genomics study against two widely used reference P. aeruginosa strains (PAO1 and PA14). PA1-Petro has a genome of 6,893,650 bp, the largest among the three analyzed in this study, with a 65.87% GC content. The analyzes resulted in a wide repertoire of 544 unique genes in PA1-Petro, and the highest copy numbers of common genes among the three strains (PA1-Petro, PAO1 and PA14). Unique sequences are hypothetical proteins, prophage sequences, mobile genetic elements, transcriptional regulators, metal resistance genes to copper, tellurium and arsenic, type IE CRISPR-Cas, Type VI Secretion System (T6SS)-associated proteins, and a toxin-antitoxin system. Taken together, these results provide intriguing insights on adaptive evolution within PA1-Petro genome, adding unprecedented information to the species’ plasticity and ubiquitous characteristics.

Numerical Investigation on Injected-Fluid Recovery and Production Performance following Hydraulic Fracturing in Shale Oil Wells

Currently, volume fracturing of horizontal wells is the main technology for shale oil development. A large amount of fracturing fluid is injected into the formation, but the flowback efficiency is very low. Besides, the impact of fluid retention on productivity is not fully clear. There is still a debate about fast-back or slow-back after fracturing, and the formulation of a reasonable cleanup scheme is lacking a theoretical basis. To illustrate the injected-fluid recovery and production performance of shale oil wells, an integrated workflow involving a complex fracture model and oil-water production simulation was presented, enabling a confident history match of flowback data. Then, the impacts of pumping rate, slick water ratio, cluster spacing, stage spacing and flowback rate were quantitatively analyzed. The results show that the pumping rate is negatively correlated with injected-fluid recovery, but positively correlated with oil production. A high ratio of slick water would induce a quite complex fracture configuration, resulting in a rather low flowback efficiency. Meanwhile, the overall conductivity of the fracture networks would also be reduced, as well as the productivity, which indicates that there is an optimal ratio for hybrid fracturing fluid. Due to the fracture interference, the design of stage or cluster spacing is not the smaller the better, and needs to be combined with the actual reservoir conditions. In addition, the short-term flowback efficiency and oil production increase with the flowback rate. However, considering the damage of pressure sensitivity to long-term production, a slow-back mode should be adopted for shale oil wells. The study results may provide support for the design of a fracturing scheme and the optimization of the flowback schedule for shale oil reservoirs.

Case Study: Oil Production Optimized With Autonomous Inflow Control Devices Offshore Malaysia

_ Advanced well completions have proven to be an effective method of moderating gas breakthrough while producing a thin oil rim when placed in a heterogenous, carbonate reservoir. In addition, several studies have proven that the application of autonomous inflow control devices (AICDs) acts as a type of insurance policy against geological and dynamic reservoir uncertainties to reduce the risk and variation in the expected oil production profiles. During 2019 and 2020, Sarawak Shell Berhad conducted development campaigns in the central Luconia province in a thin oil rim carbonate reservoir offshore Sarawak, Malaysia. The horizontal, approximately 6,000-ft development wells were expected to intersect with different geological layers with varying rock properties, resulting in an uneven reservoir influx toward the wellbore. Oil production from these wells was expected to suffer severely from early gas and water breakthrough. To produce the oil rim without the risk of early gas production, global production optimization specialist, Tendeka, incorporated FloSure AICDs in the lower completion design at the reservoir interface along the horizontal section of the wells. As an active flow control device, the technology delivers a variable flow restriction in response to the properties of the fluid entering the wellbore and the rate of flow passing through it to help manage gas coning/cusping risks. The fluid is then lifted to surface with natural in-situ gas lift built into the upper completion. A three-phase development was planned for the field, and to date, two phases have been completed. New-Generation ICD The first AICD completion was installed in Norway in 2008 and widely implemented in the Troll field in 2013 with very encouraging results (SPE 159634). However, its use is relatively new to both the Asia Pacific region and this type of application. Similar to a standard ICD which balances the influx of reservoir fluids, the FloSure AICD will delay the production of unwanted effluents prior to their breakthrough (proactive solution). However, once a breakthrough occurs, the device restricts the production of unwanted effluents with lower viscosity, such as gas (in light oil applications) and both gas and water in viscous oil production (reactive solution) (OTC 30403, OTC 30363, SPE 193718). The device delivers a variable flow restriction in response to the properties of the fluid and the rate of flow passing through it. Flow enters the device through the nozzle in the top plate of the body. This impacts the disk and spreads radially through the gap between the disk and the top plate, then turns around the top plate and is discharged through several outlet ports in the body (Fig. 1). The overall geometry of the device is critical to its ability to balance these forces effectively and create the desired fluid-dependent pressure drop. Field A employed 7.5-mm AICD valves to match the performance of the devices to the potential well flow rate. The oil, water, and gas viscosities are 0.40 cP, 0.27 cP, and 0.018 cP, respectively, at downhole flow conditions.

Stochastic multi-objective optimization approaches in a real-world oil field waterflood management

Multi-objective differential evolution with hybrid local dynamic search algorithm (HMODE-DLS) and non-dominated sorting genetic algorithm (NSGA-II) are applied successfully in a reservoir sector model of a Middle Eastern real-world oil field under waterflood development. The Pareto solutions of the two objectives of maximum oil production and minimum water production obtained by the two algorithms are analyzed and compared in this study. The sector model consists of four oil producers and three water injectors and it is run for ten years with twenty time-steps of six months each. A total of 140 decision variables are defined as bottom-hole pressures for the four producers and water injection rates for the three water injectors at each time step (i.e. 7 variables by 20 time-steps). The optimal Pareto solution is obtained at 12,600 function evaluations by HMODE-DLS with 70% convergence improvement compared to 42,000 objective evaluations by NSGA-II. Results show that NSGA-II generated more optimum solutions in the lower range (i.e. less than 480 thousand m3 (Mm3) total oil production) whereas, the hybrid MODE-DLS has a more optimum solution in the higher range of the Pareto front. The net flow method (NFM) is usedin this study to select the best optimal solutions from the Pareto front solutions based on the weight of the objective function chosen by the decision-maker. By using the entropy weight criteria, the best optimal solution of high oil production determined is 540.45 Mm3 at the HMODE-DLS Pareto front. On the other hand, the best optimal solution of low oil production obtained is 469.93 Mm3 at the NSGA-II Pareto front. The combined optimal Pareto fronts obtained by NSGA-II and HMODE-DLS algorithms offer good spread and diverse solutions for the decision-maker to select and operate the field based on the operation conditions and constraints.

Membrane Distillation Technology Using for Desalination of Associated Oil Water Production and Study Efficiency of Feed Water Operation Parameter on Air Gap Membrane Distillation Process Production

In this study; membrane distillation technology using to associated oil water production desalination by air gap membrane distillation unit to removed salt from the water after separating oil product, via PTEF commercial hydrophobic membrane distillation with 0.22 µm porous and 0.011 m contact surface area, evaluated the desalination system and operation parameter for feed water effected on process production by employment the distillation under boiling point temperature that getting commercial increments and study the energy gain by calculating the GOR of the desalination process.
 The study focusing on the air gap membrane distillation desalination process by a range of temperature after primary simple sedimentation and filtration it's obtained salt rejection up to 98.9% that proves process separation efficiency. Evaluated the mean operation parameters of feed water affected on permeate water production when selected the feed temperature and flow rate with fixed coolant temperature, coolant flow rate, and air gap width to get an optimum range for feed water operation parameter to obtain optimum value to permeate water production and saving energy.

Synthesis and optimization of bentonite enforced poly (acrylamide/co- sodium dodecylbenzensulfonate) preformed particle gels for conformance control in high salinity reservoirs

Water production in the matured oil reservoir is a big concern to the petroleum industry because of increased oil production costs and water discharge problems. In the present study, Poly (Acrylamide/Co- Sodium dodecylbenzene sulfonate (SDBS)) preformed particle gels (PPG) was synthesized, characterized, and evaluated as a conformance control agent for the high-temperature and high-salinity conditions. The rheological properties, along with the chemical and thermal stability of the synthesized PPGs were enhanced through optimization by integrating new functional groups (SDBS) into their structure to resist as high as 10% salinity and 100 °C. A succession of 16 experiments with varying amounts of acrylamide, SDBS and bentonite concentrations were conducted to obtain the optimum composition to yield the best PPG. The results showed improved swelling ratio, gel strength, rheological properties and thermal stability of the PPGs synthesized. A Delay in degradation of bentonite impregnated PPGs was observed from 37 days to 120 days @100 °C, whereas the increase in water residual resistance factor was 184.6%. The use of low-cost bentonite clay as a new material, in place of costly nanoparticles in nano-PPG, would like to reduce to cost of effective water shutoff to reduce water production.

Effect of progressive irrigation water reductions on super-high-density olive orchards according to different scarcity scenarios

The cultivation of super-high-density (SHD) olive orchards in the Mediterranean Basin usually faces drought events due especially to low precipitation, high temperature and solar radiation in summer. Hence regulated deficit irrigation (RDI) strategies can be a useful tool for irrigation management to limit yield loss. Therefore, this work aimed to find the most suitable RDI strategy by placing special emphasis on phase II of fruit growth for SHD olive orchards irrigated below theoretical water requirements. Four irrigation strategies were defined according to different water availability scenarios: fully-irrigated, RDI1, RDI2 and RDI3, scaled to respectively supply 450, 350, 250 and 150 mm year-1. Tree water relations, trunk growth, fruit and oil yields, were evaluated. The study was carried out for 5 years in an ‘Arbequina’ commercial orchard (1667 trees ha-1) in Villena, Alicante (Spain). The main results showed that ‘Arbequina’ tree irrigation water productivity (both olive and oil) gradually increased as irrigation dose lowered. Olive yield depended heavily on the applied irrigation dose, with the highest olive yield for the Control trees. However, the oil yield in the RDI1 trees was similar to that of the Control trees, but strategies RDI2 and RDI3 reduced yield. All the RDI strategies diminished vegetative development, and RDI2 was the most efficient strategy for resource distribution (olive yield vs. vegetative growth). Therefore based on oil production, vegetative growth and irrigation water savings, RDI1 was the most recommendable irrigation strategy for the Arbequina’ olive trees cultivated in SHD under semi-arid Mediterranean conditions.

Synthesis of a custom-made suspension of preformed particle gel with improved strength properties and its application in the enhancement of oil recovery in a micromodel scale

The objective of this work is to develop a new Preformed Particle Gel (PPG) suspension to enhance oil production and monitor water production in a porous medium on micromodel scale. To achieve the above goal, the following synthetic method was used. At the outset, the PPG samples were synthesized with polyethylene amine (PEI) as a crosslinker, 2,2′-Azobis (2-methylpropionamidine) dihydrochloride (AAPH) as initiator and acrylamide (AM) and 2-Acrylamido-2-methylpropanesulfonic acid (AMPS) monomers to improve the strength properties of PPGs by the radical polymerization method. Also, to characterize the micro and macro structural the samples, the scanning electron microscopy (SEM), environmental scanning electron microscope (ESEM), Fourier transforms IR spectra (FTIR), and particle size distribution (PDS) analytical techniques were used. The viscoelastic properties, structural strength, thermal stability and swelling capacity in two different conditions of room temperature (in distilled water) and at the temperature of 90 °C (in both distilled water and brine solution with 10 wt% NaCl) were analyzed for the samples prepared in this work. Based on the results of the frequency sweep test (FST), not only the formation of the 3D structure of hydrogels was confirmed but also the effects of material composition on the rigidity modulus G′(∞) in the structure of PPGs were investigated. The results of swelling and the FST tests led to introduce a novel and custom-made formulation for the suspension of (AM-AMPS)/PEI with an optimal composition of crosslinker and AM/AMPS. The flow curve of the customized sample with optimal PPG concentration also indicated that the Newtonian behavior of the new suspension at the lowest and highest shear rates and a shear-thinning behavior in the middle region, i.e., 0.01 to 1000 1/s. Additionally, to further examine the new PPG, the Thermalgravimetric Analysis (TGA), Derivative Thermogravimetry (DTG) and Temperature Sweep Test (TST) methods were used to evaluate the thermal stability of the 1 wt% PPG suspension. According to the TGA and DTG results, the synthesized sample could maintain its structure up to 260 °C and the destruction of the structure occurred at the temperature above 520 °C. Also, the results of the TST test confirmed the rubbery plateau state with increasing the system temperature. Finally, the micromodel technique was used to study the effect of injection of the PPG suspension on the amount of oil recovery. Therefore, the optimal PPG suspension was injected into an oil saturated micromodel and the amount of oil recovery was measured as 81%. Based on the results of the micromodel experiments, it was concluded that the oil recovery from the injection of the PPG suspension could increase 2.5 times more comparing to that of water injection with no PPG suspension.

Simulation method of oil-water two-phase transient flow in dual-porosity system in tight reservoir

The fracturing development process of tight oil reservoir has the characteristics of multiphase seepage and heterogeneity of reservoir fracture network, which makes it difficult to simulate the oil-water flow of multi-fractured horizontal well. In this paper, a novel mathematical analytical simulation method for oil-water two phase transient flow in matrix-fracture dual-porosity system of tight oil reservoirs is proposed, which considers the characteristics of oil-water two-phase seepage in matrix-hydraulic fracture-fracture network dual-porosity system. At the same time, a dynamic drainage-area is introduced to solve the fracture heterogeneity problem. The material balance equations in the three regions of matrix-hydraulic fracture-fracture network system are solved based on Newton-Raphson method. The changes of average pressure, cumulative oil-water production and daily oil-water production with time in different regions of fractured horizontal wells during production are accurately and systematically simulated and predicted. With laboratory data as constraints, this method can reduce the amount of analytical calculation, improve the understanding of oil-water two-phase transient flow in matrix-fracture dual-media system of tight oil reservoirs and guide the efficient fracturing development of tight reservoirs.

Optimizing Water Injection Performance by Using Sector Modeling of the Mishrif Formation in West Qurna-1 Oil Field, Southern Iraq

The regular job of a reservoir engineer is to put a development plan to increase hydrocarbon production as possible and within economic and technical considerations. The development strategy for the giant reservoir is a complex and challenging task through the decision-making analysis process. Due to the limited surface water treatment facility, the reservoir management team focuses on minimizing water cut as low as possible by check the flow of formation and injected water movement through the Mishrif reservoir. In this research, a representative sector was used to make the review of water injection configuration, which is considered an efficient tool to make study in a particular area of the entire field when compared with the full-field model on the basis of time-consuming and computational analysis. The sector model was neighboring by extra grid blocks and three pseudo wells as injector wells to realize the pressure on the sector boundary, which attained an acceptable history matching. The fluid model and physics model were introduced by using Pressure Volume Temperature data of well involved in the study area and two relative permeability curves. Fourteen wells were utilized in this work, four wells are injectors, and the rest are producer. The development scenarios were implemented by setting various targets of oil production and different water injection rates required for pressure maintenance operations. Optimization of water cut has been applied by adjustment of production and injection rates and shut off the high water cut intervals. The results obtained from this study showed that the inverted 9-spot has a good recovery which is illustrated in the case_2C, the production rate was (49,000 STB/D) with minimum water cut (27.5%) as compared with a five-spot pattern.

Sugarcane bagasse for environmentally friendly super-absorbent polymer: synthesis methods and potential applications in oil industry

Super-absorbent polymer (SAP) is able to absorb water by multiple times more than its own weight. Sugarcane bagasse (SCB) raw material has been excessively produced as a byproduct in sugar factory. The synthesis of SAP from SCB creates a balance between the utilization of industrial by-product and the resulted environmentally friendly material. In oil production water might be a troublesome, thus minimizing water production while extracting oil is essential. Besides, diversion of the flow in heterogeneous reservoir optimizes the oil production. SCB-SAP might have the potential to act as a water absorbing agent and flow diverter by taking the advantage of SAP high swelling ratio characteristic. This study provides the information of SCB-SAP synthesis methods and highlights the current application of SAP in oil industry, including the laboratory studies and field tests.

Comparison Between Homogenous and Heterogeneous Reservoirs: A Parametric Study of Water Coning Phenomena

Water coning is the biggest production problem mechanism in Middle East oil fields, especially in the Kurdistan Region of Iraq. When water production starts to increase, the costs of operations increase. Water production from the coning phenomena results in a reduction in recovery factor from the reservoir. Understanding the key factors impacting this problem can lead to the implementation of efficient methods to prevent and mitigate water coning. The rate of success of any method relies mainly on the ability to identify the mechanism causing the water coning. This is because several reservoir parameters can affect water coning in both homogenous and heterogeneous reservoirs. The objective of this research is to identify the parameters contributing to water coning in both homogenous and heterogeneous reservoirs. A simulation model was created to demonstrate water coning in a single- vertical well in a radial cross-section model in a commercial reservoir simulator. The sensitivity analysis was conducted on a variety of properties separately for both homogenous and heterogeneous reservoirs. The results were categorized by time to water breakthrough, oil production rate and water oil ratio. The results of the simulation work led to a number of conclusions. Firstly, production rate, perforation interval thickness and perforation depth are the most effective parameters on water coning. Secondly, time of water breakthrough is not an adequate indicator on the economic performance of the well, as the water cut is also important. Thirdly, natural fractures have significant contribution on water coning, which leads to less oil production at the end of production time when compared to a conventional reservoir with similar properties.

A practical integrated forecast method for estimated ultimate recovery (EUR) and well production performance after water breakthrough during waterflooding in naturally fractured reservoirs (NFRs)

It is both an opportunity and a challenge to develop naturally fractured reservoirs (NFRs) effectively and efficiently, especially with waterflooding development measures. In order to make production performance analysis and estimated ultimate recovery (EUR) forecast for NFRs during waterflooding easier and more widely applicable, a practical integrated method was established in this study based on two-phase flow characteristics of oil and water in NFRs and classic reservoir engineering theories of non-piston like displacement of oil by water, which consists of several novel practical forecast models for EUR and well production performance. Firstly, the well-controlled original oil in place (OOIP) of an NFR can be quickly fitted and obtained from actual production data by the established relationship between cumulative oil production and cumulative water production. Then, the maximum cumulative oil production, namely, the EUR of the production well can be determined when water cut is infinitely close to 1, and the well production performance in the future can be conveniently forecasted by the derived generalized relationships between water cut and other production characteristic parameters including cumulative water (or oil) production and recovery factor of well-controlled OOIP (or EUR). A lab-scale and two field-scale NFR models with different well patterns were established and simulated so as to verify whether the practical forecast models proposed in this paper are reliable and accurate, and comparison results indicated that all these models are in good agreement with the simulated production data. Sensitivity analysis for the curve fitting model of well-controlled OOIP demonstrated that viscosity ratio of water phase to oil phase has an enormous influence on the model and residual oil saturation also has a greater influence on the model compared with connate water saturation. In addition, two actual production wells in the X oilfield were selected as case wells for field applications and it was found that the unified type-curve for recovery factor performance forecast can be determined and employed for different production wells in the same oilfield unless the viscosity ratio of water phase to oil phase, the connate water saturation and the residual oil saturation do not change comparatively. The authors believe that the practical integrated forecast method established in this study is of great help for field reservoir engineers to analyze production data and forecast EUR and well production performance in NFRs during waterflooding development processes more quickly and conveniently. • A practical model for EUR forecast during waterflooding in NFRs was proposed. • Well-controlled OOIP can be conveniently fitted by actual field production data. • Well production performance can be forecasted by the derived integrated models. • The novel method is of great help for field engineers to quickly perform PDA.

Two-Step Predict and Correct Non-Intrusive Parametric Model Order Reduction for Changing Well Locations Using a Machine Learning Framework

The objective of this paper is to develop a two-step predict and correct non-intrusive Parametric Model Order Reduction (PMOR) methodology for the problem of changing well locations in an oil field that can eventually be used for well placement optimization to gain significant computational savings. In this work, we propose a two-step PMOR procedure, where, in the first step, a Proper Orthogonal Decomposition (POD)-based strategy that is non-intrusive to the simulator source code is introduced, as opposed to the convention of using POD as a simulator intrusive procedure. The non-intrusiveness of the proposed technique stems from formulating a novel Machine Learning (ML)-based framework used with POD. The features of the ML model (Random Forest was used here) are designed such that they take into consideration the temporal evolution of the state solutions and thereby avoid simulator access for the time dependency of the solutions. The proposed PMOR method is global, since a single reduced-order model can be used for all the well locations of interest in the reservoir. We address the major challenge of the explicit representation of the well location change as a parameter by introducing geometry-based features and flow diagnostics-inspired physics-based features. In the second step, an error correction model based on reduced model solutions is formulated to correct for discrepancies in the state solutions at well grid blocks expected from POD basis for new well locations. The error correction model proposed uses Artificial Neural Networks (ANNs) that consider the physics-based reduced model solutions as features, and is proved to reduce the error in QoI (Quantities of Interest), such as oil production rates and water cut, significantly. This workflow is applied to a simple homogeneous reservoir and a heterogeneous channelized reservoir using a section of SPE10 model that showed promising results in terms of model accuracy. Speed-ups of about 50×–100× were observed for different cases considered when running the test scenarios. The proposed workflow for Reduced-Order Modeling is “non-intrusive” and hence can increase its applicability to any simulator used. Additionally, the method is formulated such that all the simulation time steps are independent and hence can make use of parallel resources very efficiently and also avoid stability issues that can result from error accumulation over time steps.