Maintain Reservoir Pressure Research Articles

Reservoir water of Boryslav oilfield as a source of iodine and bromine

Formulation of the problem. Associated reservoir water is valuable hydro-mineral raw material. Its practical use in economic activity has not been found, and is now irretrievably lost by returning to the corresponding geological horizons to maintain reservoir pressure. The purpose of the article. The purpose of this work is to analyze the expediency of extracting iodine from the reservoir waters of Boryslav oilfield. Methods. To do this, various scientific methods were used, namely: observation, description; analysis - during studying the results of reservoir water samples from the deposits of Precarpathian; synthesis - for the allocation of wells and objects with industrial iodine content in samples of reservoir water within Boryslav oilfield; mathematical methods - a volumetric method to calculate reservoir water. Results. Results of reservoir water samples from the Precarpathian region deposits were analyzed in the article. It is highlighted that fifty-four samples of water with iodine content of 50 mg/l and more belong to wells and Boryslav oilfild, 13 belong to objects of oil deposits in the Inner zone of the Carpathian forge, the remaining 31 belong to the gas fields within Exterior Zone. For the first time, volumes of reservoir water from the Yamnian horizon of the Oriv-Ulychne deposit and its reserves of iodine and bromine were calculated. According to preliminary estimates, iodine reserves amount to 7,128 tons, bromine reserves amount to 8,311 tons. Based on these calculations, it is proposed to use also iodine-bromine mineralized mineral water in the forge zone of the Carpathians for the large industrial production of iodine based on Boryslav oilfield. Scientific novelty and practical significance . The research results were used by Boryslav Town Council to prepare an investment project Establishment of an Iodine Production Plant based on the reservoir waters of Boryslav Oilfield in the town of Boryslav, Lviv Oblast, which can be implemented at the expense of the state fund of regional development.

Prediction of the Deposition of Sulfate Salts Taking the Content of Strontium during the Exploitation of Oil Fields into Account

Based on the experience of developing an oil field on the Caspian Sea shelf, which was initially exploited with injection of seawater into the oil-bearing beds to maintain reservoir pressure, the deposition of sulfate salts under reservoir conditions is predicted. The prediction of sulfate deposition is made in two ways: analytical calculations according to the method of J.E. Oddo and M.B. Thomson and computer modeling. The prediction took the strontium content in the formation waters of the oil-field into account, which is usually ignored in production practice. It has been established that the prediction by computer modeling is more accurate; in particular, it considerably expands the temperature limits of anhydrite precipitation. The amount of potentially precipitable sulfate salts found by computer modeling has shown that the mass of deposited calcium and strontium sulfates is rather large, which can significantly reduce the permeability of the reservoir.

Forecast of the deposition of sulfate salts, taking into account the content of strontium, in the exploitation of oil deposits

Based on the experience of developing an oil fieled on the Caspian Sea shelf, which was initially operated with injection of seawater into oil-bearing seams to maintain reservoir pressure, a forecast was made for the deposition of sulfate salts in reservoir conditions. The forecast of sulphate deposition is carried out in two ways: analytical calculations by the method of J.E. Oddo and M.B. Thomson and computer modeling. The prognosis took into account the strontium content in the reservoir waters of the deposit, which is usually ignored in oilfield practice. It has been established that computer modeling gives a more accurate prediction, in particular, considerably expands the temperature limits of anhydrite precipitation. The determination of the amount of potentially sulphate salts potentially found in computer simulations has shown that the mass of deposited calcium and strontium sulfates is large enough that it can significantly reduce the permeability of the reservoir.

PREPARATION OF PRODUCED WATER FOR PRESSURE MAINTENANCE SYSTEM IN LOW PERMEABLE OIL RESERVOIR

Oil production in Russia is mainly with maintaining reservoir pressure by injection of bottom water. Based on the experience of exploitation of oil fields at the late stage, it is concluded that the depth of cleaning produced water is insufficient. This leads, on the one hand, to colmatation of the reservoir and reduce the oil recovery factor, on the other hand, water pollution by oil, heavy metals, hydrogen sulfide. Sampling of bottom water after cleaning a pipe separator showed that they contained more than 1000 mg/l film of oil, about 100 mg/l of emulsified oil, up to 7 mg/l of iron, which is extremely unsatisfactory for subsequent injection of water into oil-containing reservoirs. Performed technological research on the purification of produced water by the method of sedimentation using coagulant and alkalizing reagent and water purification innovative electrochemical filters with active mineral download. The purified produced water oil concentration does not exceed 3 mg/l, suspended solids of 2 mg/l iron 0.3 mg/l. The technological scheme of preparation of produced water for use in the formation pressure maintenance system.

Evidence of Multi-Component Ion Exchange in Dolomite Formation during Low Salinity Waterflooding

Low salinity waterflooding is a technique performed in many oil reservoirs around the globe. The technique is simply implemented by injecting water with very low ionic activity compared to formation water into an injection well. The injected water will increase reservoir pressure that is compulsory to drive oil moving toward production well. More than just maintaining reservoir pressure as obtained from conventional waterflooding, low salinity water creates shifting of surface condition, resulting in additional amount of liberated oil. Nevertheless, exact oil recovery mechanisms are still discussed. Among these proposed mechanisms, Multi-component Ion Exchange (MIE) together with wettability alteration is believed to be a major mechanism leading to higher oil recovery compared to conventional waterflooding. In this study, detection of calcium and magnesium ions which are Potential Determining Ions (PDI) for carbonate reservoirs are detected during the coreflood experiment. Dolomite rock sample is used to represent carbonate formation and detection of previously mentioned ions is performed by complexometric titration of the effluents. From the study, it is observed that during conventional waterflooding and low salinity waterflooding at low temperature of 30 degrees Celsius, calcium and magnesium ions in the produced water is increased compared to the amount of these ions in the injected water. This incremental of ions can be explained by the dissolution of calcium and magnesium from dolomite which is chemically composed of calcium magnesium carbonate. At this temperature, the portion of calcium ion is always less than magnesium ion even though the amount of calcium ion is higher than magnesium ion in injected water. However, at higher temperatures which are 50 and 70 degrees Celsius, ratio of calcium and magnesium ions in injected and produced water is reversed. Disappearance of magnesium ion in the effluent is more obvious especially at 70 degrees Celsius and by low salinity waterflooding. This can be explained that at lower temperature, calcium ion disappears to form of calcium carboxylate complex with oil and at higher temperature, magnesium ion disappears as magnesium can start to form magnesium carboxylate complex with oil and hence, the amount of both calcium and magnesium ions is decreased compared to lower temperature. In dolomite reservoir, since both calcium ions and magnesium ions are provided from dissolution mechanism, the benefit from multi-component ion exchange will occur at high temperature as both calcium and magnesium ions will be consumed for oil recovery mechanism.

CO2 Utilization for Enhance Oil Recovery with Huff-N-Puff Process in Depleting Heterogeneous Reservoir

Currently, the reduction of carbon dioxide (CO2) emission has been increasingly concerned by many industries because CO2 is recognized as one of the main greenhouse gases. Some oil industries have applied commercial processes to enhance oil recovery and reduce greenhouse gas known as CO2 enhanced oil recovery (CO2-EOR). And one of the effective methods is the cyclic CO2 injection or CO2 Huff-n-Puff. This method is applied CO2 to extract additional oil from depleting reservoir by reducing oil viscosity and maintaining reservoir pressure. Accordingly, CO2 utilization is the key factor to success the CO2 Huff-n-Puff process in depleting oil reservoir. Consequently, it becomes the objective of this research which is to investigate the sensitivity of CO2 utilization and to evaluate the performance of CO2 Huff-n-Puff process in depleting heterogeneous reservoir by using numerical simulation. From the simulation, the results report that the highest sensitive parameter of CO2 utilization is CO2 injection rate, followed by CO2 injection time, and number of cycle. On the other hand, the lowest sensitivity is soaking time due to low pressure buildup rate in depleting reservoir. Moreover, higher CO2 utilization can be obtained by increasing of CO2 injection rate and time. Likewise, the increasing of CO2 Huff-n-Puff cycle can rise CO2 utilization due to the expansion of drainage area and reservoir pressure support. Finally, the carbon capture and storage technologies can help reduce CO2 utilization of Huff-n-Puff process by re-injecting of CO2 in subsequent cycles and storing of CO2 into depleted reservoir after crude oil is not economically produced.

Modeling cementation in porous media during waterflooding: Asphaltene deposition, formation dissolution and their cementation

Waterflooding due to water availability, ease and low cost is the most common technique for maintaining reservoir pressure and increasing the recovery of oil. However, the injected water may chemically interact with the reservoir fluids and rock, and it could cause asphaltene deposition and rock dissolution. This paper provides details of the state of the art research performed on characterizing these processes and their effects. It is observed that the dissoluted particles may precipitate on the deposited asphaltene in the porous media leading to cementation. Where this cementation might cause an irreversible and permanent impairment of reservoir porosity and permeability, reducing the productivity of the whole waterflooding operation: decreasing oil productivity and water injectivity.In the development of the proposed model, the radial flow geometry has been adopted and a solution is sought to predict the deposition of asphaltene, rock dissolution and precipitation with respect to time and space. The developed model also predicts the phenomenon of cementation in the porous media and different factors that will enhance cementation. These factors include: asphaltene concentration, water injection rate, injection period, the depth and temperature of the reservoir. It is found from the detailed analysis that the cementation remain very low but it could cause complete pore plugging with time. The derived cementation model assumes that the temperature of reservoir remains constant during waterflooding and the interfacial tensional forces are negligible. But practically the latter may support the cementation process.

Multi-porosity multi-physics compositional simulation for gas storage and transport in highly heterogeneous shales

Shale gas reservoir is comprised of highly heterogeneous porosity systems including hydraulic/secondary fractures, inorganic and organic matrix. Multiple non-Darcy flow mechanisms in the shale matrix further bring challenges for modeling. In this paper, we developed a framework combining a multi-physics compositional simulator with Multi-Porosity Modeling preprocessor for gas storage and transport in shale. A Triple-Porosity Model is used to characterize the three porosity systems in shale gas reservoirs. In the fracture porosity the heterogeneous impact of secondary fractures distribution on matrix-to-fracture fluid transfer is revealed by shape factor distribution. They are upscaled with superior accuracy from a detailed Discrete Fracture Network Model (DFN) sector model, where orthogonal hydraulic fractures are explicitly discretized. With the occurrence of nano-pores in shale matrix, the interaction between pore-wall and gas molecules is considered via Knudsen diffusion and gas slippage. Gas adsorption on the pore-wall of organic matrix is modeled by extended Langmuir isotherm. The inter-porosity and intra-porosity connectivities in the Triple-Porosity Model are flexibly controlled by arbitrary connections. Our results show that gas production in the Triple-Porosity Model with shape factor upscaled from DFN exhibits different production performance from models with uniform shape factor distribution. The deviations are caused by the dominance of different regions at different production periods. Connection topology in the shale gas reservoir is also comprehensively assessed. We demonstrate that the intra-porosity connections in the inorganic and organic matrix have negligible impact on the global gas flux, while the inter-porosity connections have different levels of importance for the gas production. Moreover, different combinations of flow and storage mechanisms are investigated. We show that Langmuir desorption maintains reservoir pressure, but gas slippage and Knudsen diffusion accelerate the pressure drop. Both mechanisms contribute to improve the gas production and the consideration of them simultaneously improve gas production most.

PROBLEMS OF COMPATIBILITY OF FORMATION WATER AND INJECTED WATER IN THE OIL FIELDS OF WESTERN SIBERIA

A method of maintaining reservoir pressure using a system for formation pressure maintenance of oil reservoirs in the oil fields of Western Siberia is extremely wide-spread. In oil fields as a system for formation pressure maintenance are widely used almost all types of water resources including surface water, groundwater and industrial wastewater. Different calculation methods for predicting the formation and precipitation of salts based on quantitative criteria are used to forecast possible precipitation of calcium carbonate in the flooded oil reservoir areas.

Regional- to Reservoir-scale Evaluation of CO2 Storage Resource Estimates of Coal Seams

Unmineable coal seams are an important target for investigating the economic viability of carbon capture and storage technology owing to their potential for simultaneous CO2 storage and enhanced coalbed methane production. As such, recent developments in integrated system models are aiming to explicitly incorporate coal seam storage and enhanced methane production into their economic analyses, however, such implementation currently relies on fairly uncertain prospective resource estimates derived from regional-scale analyses. In this paper, we evaluate the uncertainty of such prospective resource estimates, both for CO2 storage and for CO2 utilization potential (i.e., enhanced coalbed methane production from CO2 injection) via comparison to results from more detailed, local-scale reservoir simulations at numerous locations. Reservoir-scale simulations incorporate the dynamic system response to CO2 injection, whereas regional-scale prospective resource estimates rely on volumetric calculations of original gas-in-place from static geological models combined with assumed recovery factors.Results based on a case study of 12 different locations in the Illinois Basin, USA suggest that prospective resource estimates for CO2 storage may be systematically biased towards over-estimation. By developing a set of low-, mid-, and high-range estimates from model simulations, a total of 36 comparisons were made to the prospective resource estimates, of which 35 showed significantly lower results for the model-based estimates. Model sensitivity testing of variable CO2 injection rates indicated that the requirement to maintain reservoir pressure below the fracture gradient threshold is in part responsible for the lower limit of storage resource estimates obtained from the reservoir simulation results versus the prospective resource methodology which neglects such processes. In terms of enhanced methane recovery, results were far more comparable between the two methods for the low- and mid-range set of estimates, whereas the high-range estimates were still notably larger using the prospective resource methodology. We conclude that utilizing prospective resource estimates of enhanced coalbed methane potential in integrated system models appears feasible for the more conservative range of estimates, whereas CO2 storage estimates of coal seams are likely to produce overly optimistic results in the system model. We also note that for the Illinois Basin case study, both the modelling results and the regional-scale results indicate that a significant amount of additional well drilling beyond the existing coalbed methane infrastructure would need to be conducted in order for coal seams to be a viable alternative to other options in the region such as oil and gas reservoirs and deep saline formations.

STUDY OF CONDENSATION PROCESS DURING WELL OPERATIONUNDER ABNORMALLY HIGH RESERVOIR TEMPERATURES (BY EXAMPLE OF THE YUBILEINOYE GAS-CONDENSATE FIELD)

Some of gas-condensate fields lying at great depths are characterized by abnormally high reservoir temperatures. One of the problems during the operation of wells at depleted fields which are developed without methods to maintain reservoir pressure is fluid accumulation at the bottom. The Yubileinoye gas-condensate field is selected as an example for study. At the field abnormally high reservoir temperature is combined with low molecular weight of formation fluid. Since the change in the content of components produced from the formation to the surface of the gas-condensate mixture changes condensate emission even at the constant volume of gas production. It is important to understand the physical processes occurring in the operation of wells.

Assessing the Utility of High-level CO2 Storage and Utilization Resource Estimates for CCS System Modelling

The challenge of evaluating the economic and technical feasibility of implementing carbon capture and storage technology has led to new developments in integrated system modelling. Of particular importance is the explicit implementation of CO2 utilization opportunities such as enhanced oil recovery because storage-only projects have struggled to move beyond the consideration phase. The availability of results from high-level, prospective resource assessments for both CO2 storage and utilization makes such implementation possible, however, the uncertainty in resource estimates can have significant impact on system modelling results. In this paper, we evaluate the uncertainty in low-, mid-, and high-range resource estimates that have recently been implemented within a state-of-the-art integrated system model by comparing the estimates to detailed, dynamic reservoir-scale simulations at numerous locations. We focus specifically on utilization and storage in conventional oil and gas reservoirs, since enhanced oil recovery appears to be a key component for the economic viability of current carbon capture and storage projects.Results from a case study involving thirteen different reservoir locations suggest that the high-level resource estimates may be biased towards over-estimation of both CO2 utilization and storage. For CO2 utilization, the high-level resource estimates exceeded reservoir simulation results at twelve of the thirteen locations, often by a factor of three or greater. For CO2 storage, the low-range set of resource estimates was in good agreement between the two approaches. However, comparison of the mid- and high-range estimates indicated again a tendency towards over-estimation with the reservoir simulation results confined to a lower and narrower range of estimates. Model sensitivity analysis indicated that differences between the two approaches can in part be attributed to the dynamic impact of CO2 injection rate, but the requirement to maintain reservoir pressure below the fracture gradient criteria is an important limitation that is neglected in the resource estimate approach. Results from this study suggest that utilizing CO2 resource estimates from high-level assessments is feasible for integrated system modelling, but implementation should be focused towards the conservative, low-end range of estimates in order to provide the most reliable results for project risk assessment and techno-economic analysis.

Numerical simulation on ferrofluid flow in fractured porous media based on discrete-fracture model

Abstract Water flooding is an efficient approach to maintain reservoir pressure and has been widely used to enhance oil recovery. However, preferential water pathways such as fractures can significantly decrease the sweep efficiency. Therefore, the utilization ratio of injected water is seriously affected. How to develop new flooding technology to further improve the oil recovery in this situation is a pressing problem. For the past few years, controllable ferrofluid has caused the extensive concern in oil industry as a new functional material. In the presence of a gradient in the magnetic field strength, a magnetic body force is produced on the ferrofluid so that the attractive magnetic forces allow the ferrofluid to be manipulated to flow in any desired direction through the control of the external magnetic field. In view of these properties, the potential application of using the ferrofluid as a new kind of displacing fluid for flooding in fractured porous media is been studied in this paper for the first time. Considering the physical process of the mobilization of ferrofluid through porous media by arrangement of strong external magnetic fields, the magnetic body force was introduced into the Darcy equation and deals with fractures based on the discrete-fracture model. The fully implicit finite volume method is used to solve mathematical model and the validity and accuracy of numerical simulation, which is demonstrated through an experiment with ferrofluid flowing in a single fractured oil-saturated sand in a 2-D horizontal cell. At last, the water flooding and ferrofluid flooding in a complex fractured porous media have been studied. The results showed that the ferrofluid can be manipulated to flow in desired direction through control of the external magnetic field, so that using ferrofluid for flooding can raise the scope of the whole displacement. As a consequence, the oil recovery has been greatly improved in comparison to water flooding. Thus, the ferrofluid flooding is a large potential method for enhanced oil recovery in the future.

A method to calculate reasonable water injection rate for M oilfield

In recent years, M oilfield has entered into high water cut stage. Two main problems are imposed in the process of development including sharp water cut rising rate and rapid oil production decline. These problems are difficult to solve, which may bring other problems. In order to slow down production decline rate and control the rising rate of water cut, it is necessary to control water injection rate. However, oil production rate can be affected if water injection rate is too low to provide enough water volume for maintaining reservoir pressure. A method to calculate reasonable injection–production ratio and predict water cut is provided in this paper. Its main mechanism is to resolve above contradictions by calculating reasonable water injection rate. Firstly, an equation to calculate reasonable injection–production ratio is deduced by material balance equation. It considers several parameters including rate of pressure recovery, water cut and other production indexes. Secondly, reasonable oil production rates and water cut of future 10 years are predicted. Oil production is predicted by the law of production decline, and water cut is predicted by regression equation of water drive characteristic curve. Lastly, reasonable water injection rates of next 10 years are calculated through predicted injection–production ratios and liquid production rates. Taking M oilfield as an example, this paper presents a method to determine reasonable water injection rate of multilayer sandstone water drive reservoir.

Asphaltene-Prevention Work Flow Enhances Oil Production in High-Temperature Fractured Carbonate Reservoirs

Summary Asphaltene precipitation is a common phenomenon in mature reservoirs that seriously impairs oil production. In high-temperature (HT) fractured carbonate reservoirs, the situation becomes critical when asphaltene precipitates at reservoir conditions, blocking the production channels and starting a cycle of production decline in which additional pressure drop increases the precipitation of the asphaltene fraction. Therefore, it is essential to make an early diagnosis of the problem and deliver an optimal solution to avoid further production decrease. A proper diagnosis regarding the point of precipitation along the production path requires a complete analysis of the well's production behavior and reservoir characteristics. To avoid asphaltene precipitation inside the rock matrix, different methods can be applied: maintaining reservoir pressure above the asphaltene-onset pressure, avoiding coproduction of incompatible reservoir fluids, adjusting artificial-lift conditions, or injecting solvents with inhibitors or dispersants. In two mature fields in southern Mexico that have been producing since 1995, an operator needed to determine where the asphaltene precipitation was occurring. An integrated diagnosis work flow was instrumented that included the creation and analysis of the asphaltene-phase envelope plus an asphaltene-onset screening test by use of a solids-detection system (SDS). After coupling screening results with a pressure/temperature flowing survey, it was identified that asphaltene precipitation occurred inside the reservoir when the bottomhole flowing pressure dropped below a critical level. To address the organic deposits and unstable pressure behavior successfully, asphaltene-precipitation characterization was essential. In some cases, a decrease in oil production after executing unsuccessful matrix-cleanup treatments with solvents results from a misdiagnosis of organic precipitation or a lack of knowledge about flocculation and precipitation causes. To avoid this problem, a new methodology for the inhibition-treatment design was added to the diagnosis work flow; this methodology includes a new adsorption-type asphaltene inhibitor as part of the matrix-cleanup treatment. As a result of this diagnostic-solution work flow, an optimum bullheaded inhibition treatment was determined and applied to the candidate wells. In all study cases, the time lapse between inhibition treatments was extended by 60 days on average, resulting in steadier oil flow rates plus significant reduction in well intervention and deferred production costs. In addition, the post-treatment results showed that, in 50% of the documented interventions, the inhibitor treatment improved overall production performance by at least 10%. The systematic engineering work flow presented in this paper includes the diagnostic procedure, data from laboratory testing, chemical selection, and treatment application. Subsequent treatment results enhanced the field operator's understanding of asphaltene precipitation in the formation matrix and provided more insight into maximizing oil production with specialized technology solutions that used a novel adsorption-type asphaltene inhibitor.

Numerical simulation of ferrofluid flow in porous media under coupled magnetic and seepage fields

Water flooding is an efficient approach to maintain reservoir pressure and has been used widely to enhance oil recovery. However, preferential water pathways generated after long-term water flooding process and the strongly heterogeneous reservoirs can significantly decrease the sweep efficiency. Therefore, the utilization ratio of injected water is seriously affected. Most water-flooded reservoirs are in their late development stage, and their water cuts are more than 90%. How to develop new flooding technology to further improve the oil recovery is a pressing problem. Ferrofluids are colloidal suspensions of magnetic particles of diameter approximately 10 nm stabilized in various carrier liquids. In the presence of an external magnetic field, a ferrofluid becomes magnetized as the particles align with the magnetic field. In the presence of a gradient in the magnetic field strength, a magnetic body force is produced on the ferrofluid so that the attractive magnetic forces allow the ferrofluid to be manipulated to flow in any desired direction through control of the external magnetic field without any direct physical contact. In consideration of this properties, the potential of using the ferrofluid as a new kind of displacing fluid for flooding in oil reservoir is been studied in this paper at the first time. Considering the physical process that the mobilization of ferrofluid through porous media by application of strong external magnetic fields, we introduced the magnetic force into the Darcy equation to coupling the magnetic field and seepage flow field. The steps involved in calculating ferrofluid flow in porous media are (1) calculation of the external magnetic field strength produced by permanent magnet, (2) calculation of the magnetization using the magnetization curve of ferrofluid and initial ferrofluid saturation, (3) calculation of the magnetic force on the fluid, (4) addition of the magnetic force to the pressure gradient and gravitational body force terms, and (5) calculation of the liquid phase pressure and saturation, (6) update the magnetization based on the calculated ferrofluid saturation for the next step calculation. Using the fully implicit finite volume method to solve the mathematical model, and the validity and accuracy of the mathematical model and numerical algorithm are demonstrated through a experiment which ferrofluid flowing from left to right with an initial circular injection through oil-saturated sand in a 2-D horizontal cell. At last, based on the above the numerical simulation method, the water-flooding and ferrofluid-flooding in horizontal and vertical heterogeneous porous media have been studied: because there is a relatively higher permeability zone between injection well and production well, most of the injected water flow along the higher permeability zone and small amount of oil have been displaced, the utilization ratio of injected water is low; however, the ferrofluid can be manipulated to flow in desired direction through control of the external magnetic field, so that using ferrofluid for flooding can raise the scope of the whole displacement, as a consequence, the oil recovery has been improved more than 20% compared to water flooding. Thus, through the experiments and theoretical calculations show that: the ferrofluid flooding is a large potential method for enhanced oil recovery.

Well Placement Optimization Using a Basic Genetic Search Heuristics Algorithm and a Black Oil Simulator

In petroleum reservoir management, the essence of well placement is to develop and maintain reservoir pressure in order to achieve maximum production for economic benefits. Large production can be achieved with the placement of multiple wells but this approach is capital intensive and inefficient for the development of a reservoir. A preferable option is the optimal placement of production and injection wells so as to fully capitalize on the imbedded hydrocarbons at a relatively decreased capital investment. The aim of this study is to use developed algorithm and a black oil simulator to place wells in the zones for optimal recovery in the reservoir. Optimal production was determined out of eight scenarios created from well placement in a hypothetical reservoir (finch reservoir) using a black oil simulator, alongside an algorithm developed with java for determining the best possible locations for well placement, taking into consideration the reservoir permeability, fluid saturation, and pay zone thickness. The results of this study reveal that well placement using the engineering judgment coupled with the application of the algorithm using a black oil simulator results in better production compared to other scenarios which consider the combined effect of algorithm and black oil simulator alone.

ОБ ОБЕСПЕЧЕНИИ ЭКОЛОГИЧЕСКОЙ БЕЗОПАСНОСТИ ВОДОЗАБОРОВ ХОЗЯЙСТВЕННО-ПИТЬЕВОГО НАЗНАЧЕНИЯ НЕФТЕДОБЫВАЮЩИХ РАЙОНОВ ОРЕНБУРЖЬЯ

In the oil and gas bearing areas of the Buzuluk depression with water resources deficiency and the development of environmental pollution (OC) processes, zones of groundwater concentration have been identified, both in the upper and lower hydrodynamic floors, in order to ensure water and environmental safety of the region, and oil fields - technical water for systems Maintaining reservoir pressure. We have established that the zones of concentration of fresh groundwater are gravitating toward riverine areas and are practically absent in their parts. They are vulnerable to pollution, and they can be used as indicators of the state of the OS. To protect water resources from pollution, it is recommended to place the projected engineering infrastructure, taking into account the scheme of typing the territory for protection against pollution, built by us. To protect groundwater from pollution, barrier technologies should be used, a number of which have been developed by the authors. Our geological-geophysical and neotectonic analysis of hydrogeological materials made it possible to identify the zones of concentration of brines and saline waters, which it is advisable to replace fresh water in the systems of maintaining reservoir pressure. For the same purpose, it is necessary to utilize wastewater from oilfields that can not be effectively cleaned. The proposed set of measures will increase the level of environmental safety of the oil producing regions of the Orenburg region and with the same purpose can be used in other similar regions.

Preproduction-Deployed Scale-Inhibition Treatments in Deepwater West Africa

Summary The injection of seawater into oil-bearing reservoirs for the purposes of maintaining reservoir pressure and improving secondary recovery is a well-established, mature operation. Moreover, the degree of risk posed by deposition of mineral scales (carbonate/sulfate) to the injection and production wells during such operations has been much studied. The current deepwater subsea developments offshore West Africa and Brazil have brought into sharp focus the need to manage scale in an effective way. In a deepwater West African field, the relatively small number of high-cost, highly productive wells, coupled with a high barium sulfate scaling tendency upon breakthrough of injection seawater, meant that effective scale management was critical to achieving high hydrocarbon recovery and that even wells at low water cuts have proved to be at sufficient risk to require early squeeze application. To provide effective scale control in these wells at low water cuts, phosphonate-based inhibitors were applied as part of the acid-perforation wash and overflush stages before frac-packing operations. The deployment of this inhibitor proved effective in controlling barium sulfate scale formation during initial water production, eliminating the need to scale squeeze the wells at low water cuts (<10% basic sediment and water). To increase the volumes of scale inhibitor (SI) being deployed in the preproduction treatments and so extend the treatment lifetimes, SI was also added to the fracturing gel used to carry the fracturing sand. This paper outlines the selection methods for the inhibitor chemical for application in fracturing fluids in terms of rheology, retention/release, and formation damage, and presents the chemical-return profiles from the five wells treated (some treatments lasting longer than 300 days), along with the monitoring methods used to confirm scale control in the treated wells. Many similar fields are currently being developed in the Campos Basin, Gulf of Mexico, and West Africa, and this paper is a good example of best-practice sharing from another oil basin.

Analisis Kinerja Tenaga Pendorong Reservoir dan Perhitungan Water Influx pada Perolehan Minyak Tahap Primer (Studi Kasus Lapangan Falipu)

Primary recovery is the stage of oil production by relying on the natural ability of the driving force of the reservoir. Kind of driving force that is water drive reservoir, depletion drive, segregation drive and a combination drive. The pressure drop occurred along its produced oil from the reservoir. Reservoir so that the driving force is the main parameter in maintaining reservoir pressure balance. Through the concept of material balance is the determination of the type of propulsion quifer reservoir and the power that generates driving force parameter analysis capability and aquifer in oil producing naturally. Then do the forecasting production to limit the ability of primary recovery production phase. Combination drive depletion of water drive and the drive is a driving force in the dominant reservoir Falipu Fields with a strongly water aquifer types of drives obtained through material balance equation. Calculations using the method of water influx Havlena & Odeh used as a correction factor for determining the type of propulsion reservoir and aquifer strength. Forecasting production in the Field Falipu generate recovery factor of 41% with a pressure boundary in 2050.