Accumulated Oil Production Research Articles

Study on the Effect of Nitrogen Bubble Foam Flooding in Deep Heavy Oil Reservoirs with Edge And Bottom Water

Abstract The oil recovery rate is low, the degree of recovery is low and the water content rises fast after water flooding in deep edge and bottom water heavy oil reservoir in Lukeqin oilfield. In order to explore the method to improve the production effect, the integrated foam system of high temperature and high pressure resistant viscosity reduction and oil displacement is optimized. On the basis of clarifying the mechanism of improving the production effect of nitrogen foam flooding for deep heavy oil, taking the west area of Lukeqin oilfield as the research object, the parameter optimization design of nitrogen foam flooding for deep edge and bottom water heavy oil is carried out, such as injection section plug, gas-liquid ratio and injection-recovery ratio. The optimization results are as follows: the injected nitrogen foam slug is 0.2pv, the gas-liquid ratio is 1-1.2, and the injection production ratio is 1:1. The pilot test of 4 well groups was carried out on the site. After foam flooding, the injection pressure was increased by 5.2mpa, the daily oil production of the oil well was increased by 43T / D, the water cut was decreased by 45%, the accumulated oil production was increased by 32000 tons, and the oil recovery was expected to be increased by more than 10%. The purpose of improving the development efficiency of this type of oil reservoir was achieved. Using this optimization technology for scheme design and field implementation, the oil enhancement effect is remarkable and improves the benefit of deep thick oil development, which can provide technical support for the development of similar domestic reservoirs.

SOME FEATURES OF CONSTRUCTING DISPLACEMENT CHARACTERISTICS AND WATERING DYNAMICS

The term «displacement characteristic» (DCh) was first proposed by D. A. Efros in 1959 to indicate the dependence of the accumulated oil withdrawal on the accumulated liquid withdrawal. Subsequently, DChfound wide application in the analysis of oil field development. Many authors proposed various modifications of the DCh coordinates, but directactual measurements of development parameters were always used - annual, accumulated measurements of oil, liquid, water production, water cut, liquid, oil, and water flow rates. Characteristics of oil displacement are called graphical dependences of accumulated oil production on accumulated or current values of liquid or water production, constructed based on actual data. With the help of cold water, three tasks were solved: assessment of recoverable oil reserves, calculation of the technological effect of geological and technical measures, and calculation of technological development indicators. But the main condition for application was the immutability of the development system.Recently, dependences that use parameters such as selection from geological or recoverable oil reserves have come to be classified as chemical dependencies. These dependencies have nothing to do with DCh. Justification of geological and recoverable oil reserves is an independent task; moreover, with the help of chemical recovery, recoverable reserves are found under the existing development system. Against the background of such a confusion of concepts, the definition of the concept of «standard» chemicals is introduced, which has no real meaning for an oil development facility.The dynamics of water cut refers to the change in water cut over time, for example, depending on the time of development of reserves, geological or recoverable. The dynamics of watering in this case has nothing to do with the cold water.The dry period is of great importance when developing an oil field. With the same finaloil recovery, the longer the water-free period, the better the economic indicators.Using the Buckley-Leverett function todetermine water cut is only possible when the flow is two-phase, oil and water. It is impossible to determine the anhydrous period using the Buckley-Leverett function, since it does not exist, therefore, constructing the dynamics of water supply only based on this function is incorrect.When conducting laboratory experiments on core material, in which the heterogeneity compared to the formation is minimal and can be identified with a one-dimensional flow, the anhydrous period is significant and reaches from 0.74 to 0.94 units. of the total volume of displaced oil.For a single-layer field, where there is only one homogeneous layer, the heterogeneity is greater than for the core, but less than for a heterogeneous development object. We can talk about an analogue of a two-dimensional flow with some degree of convention.Considering that these are not laboratory studies, where measurements are carried out more accurately, but production ones, the low-water-cut period (up to 10 %) is 0.4 of the total oil production from wells with simultaneous commissioning of wells. If the wells were commissioned at different periods of time, as is always the case in fields, then the dynamics of water supply are completely different, and water supply begins earlier than when all wells are commissioned simultaneously.

On the question of comparability of relative phase permeabilities obtained by different methods

The article discusses four methods for obtaining functions of relative phase permeability (RPP): 1) approximation of point laboratory data by known correlations of Corey and LET; 2) calculation of RPP by capillary pressure curves using Burdine, Cory and Cory–Brooks models; 3) calculation of RPP by field data; 4) modification of RPP when setting up a hydrodynamic model. A new method is proposed for obtaining RPP based on field data. In this method, it is assumed that the values of the Buckley–Leverett function are equivalent to the values of the well water-cut, and the water saturation can be determined by the formula linking the accumulated oil production and the initial geological oil reserves. The methods of obtaining RPP have been tested on the example of two real objects. The results of the approbation showed that all pairs of RPPs differ markedly from each other, while different trends take place for the objects considered. The article provides an explanation of the possible reasons for the difference in the RPP. At the same time, it was found that the scale factor is not the most significant. The expediency of the conducted research is due to the need to study the level of correspondence between the functions of the RPP obtained by different methods. This will allow for a more reasoned justification of the functions of the RPP when creating and adapting a hydrodynamic model of an oil deposit.

COMPARISON OF PLOT ANALYTICAL METHODS FOR DETERMINING EXCESSIVE WATER PRODUCTION MECHANISMS IN OIL WELLS

Watering of production wells is an important factor leading to a decrease in production profitability and an increase in costs. There are several main mechanisms of excess water inflow. These are a leak in the production casing; a violation of contact between the production casing and the rock; a formation of a bottom water cone; a raising the WOC surface to the perforation interval; a breakthrough through a layer with high permeability. Mechanisms can complement each other, forming a complex integrated system. To identify them, there are three groups of diagnostic methods — geophysical research, hydrodynamic well testing and plot analytical studies. Each of these fundamentally different groups can be supplemented by field research. Specifically in this work, we considered the latter. The analysis is carried out using the example of wells in one of the deposits of an oil field of the Arkhangelsk region. In which the causes of unwanted water production have already been studied by other methods and can be considered known. The studied reservoir is massive, with carbonate hydrophobic rocks and the reserves of the entire field are predominantly concentrated in it (97 %); the oil field (in terms of reserves) is small. There are no injection wells, operation is carried out in a natural elastic water drive mode. In the article, in total, three plot analytical methods are analyzed, which are among the main ones and have different application algorithms. Both the physical principles of their application and their effectiveness in relation to specific oil field are considered. These are the methods of K. Chan; L.I. Merkulova and A.A. Ginzburg; R. Novotny. The first studies the dependence of the water-oil ratio and its derivative on time (WOR and WOR’(t)), is the most widely known and has a large number of modifications (however, here they are not considered in detail). The second is based on the study of the so-called «water-cut characteristics» (representing the dependence of the accumulated oil production vs accumulated liquid production during the water period of operation). It has more restrictions, but is also more comprehensive. The third is based on a comparison of the permeability properties of reservoirs that change during operation.

Modeling of well performance during oil reservoir development on the elastic-water-drive mode using regression analysis

One of the important tasks of analyzing oil field development is predicting well performance. For this purpose, displacement characteristics are often used, which represent the dependence of some indicators on others. To determine the parameters of these dependencies, regression analysis of historical data is used. Dependences of the choice of watering production wells with water pumped into injection wells, water or the law of the exhausted aquifer. A feature of displacement characteristics is generally considered to be that they can only be used when fluid flows in the formation are established. This is due to the fact that with the classical approach, displacement of characteristics is not observed in the explicit form of well interference. Therefore, the search for displacement characteristics, with the help of which we can talk about the mutual influence of wells, is an important factor. This is the subject of this work. Water cut and water-oil ratio (WOR) are related by a well-known formula. The paper proposes regression models for WOR. They obtained the result taking into account the classical logic of the WOR from accumulated oil production. Water cut is calculated from water saturation. The proposed regression models of water saturation are based on the analysis of equations of theories of two-phase filtration in difference form. 11 watering models were studied, two including classical ones and 9 new ones. Dependencies for reservoir and bottomhole pressures were also developed. The proposed models are intended to analyze the operation of wells during the development of an oil reservoir in an elastic-water-pressure mode. The models were tested on a real field and their effectiveness was analyzed. Some new models perform well in a selection of tests. In particular, all the proposed models give better results than the classical model: the logarithm of the water-oil ratio from the accumulation of oil production.

Assessing the potential of CO2 huff ‘n’ puff technology for enhanced oil recovery and CO2 sequestration in tight oil reservoirs

Fossil fuels utilization will produce a large amount of CO2, which causes a series of environmental problems. However, the exhaust CO2 can be used to achieve oil recovery improvement (CO2 EOR), while simultaneously allowing for the geological storage of CO2. For the unconventional reservoir, CO2 huff ‘n’ puff (HNP) is a potential technology showing promising results in laboratory experiments, while its effectiveness in enhancing oil recovery and CO2 sequestration at the reservoir scale remains uncertain. Thus, further research is needed to evaluate the CO2 HNP performance for its implementation. In this paper, we conducted a numerical simulation of the CO2 HNP process in a real tight oil reservoir (1800 m × 350 m × 10m in size) to assess its potential for improving oil recovery, CO2 injectivity, and CO2 sequestration. The results show that the accumulative oil production increased by more than 20% after the implementation of CO2 HNP. Meanwhile, CO2 HNP in tight oil reservoirs is proven capable to achieve CO2 injectivities of more than 4×107 SCm3 and CO2 storages of more than 5×106 SCm3. We designed 3 CO2 HNP schemes and found that the largest CO2 storage does not occur in the optimal scenario for oil production. A new type of CO2 HNP evaluation system considering oil production and storage capacity needs to be established. The results of the article suggest that CO2 HNP can achieve an oil production increase and CO2 storage in tight reservoirs, which has a positive significance for the sustainable development of environmental protection.

Вероятностная оценка эффективности применения метода циклического заводнения нефтяных пластов

Extraction of hard-to-recover hydrocarbons is becoming an urgent task for the entire world oil community. The development of new technologies and methods, as well as the improvement of existing ones, have become the main issue in the extraction of hydrocarbons at existing fields. The aim of the work was to develop the technology of hydrodynamic impact on the hydrocarbon deposit. The process of oil reservoirs flooding is one of the most widespread and traditional in the application of extraction of hard–to-recover oil. The most effective in terms of impact is the cyclic regime of flooding of oil reservoirs – periodic changes in fluid flow rates at injection and production wells with a phase shift of oscillations for individual groups of wells. The use of cyclic flooding in combination with an increase in the average level of injection pressures can give a significant increase in the coefficient of reservoir coverage in power. The degree of hydrodynamic connectivity of the layers along the section has a significant impact on the effectiveness of cyclic flooding. The coefficient of lithological connectivity of formations is determined by the ratio of the area of the reservoir confluence to the total area of the deposit and can characterize the hydrodynamic connectivity of formations along the section. Using the example of the D3 of the Korotkoye field, an assessment of the start-up of the wells of the PPD system was done as well as the analysis of the nature of its influence on the volume and water content of the extracted products of the D3 formation of the Korotkoye field under various injection modes using cyclic flooding. It is determined that when both injection wells are stopped for a long period, the output of the produced products decreases to 25%. The analysis of the total oil flow rate showed that in the variants with well shutdowns there is a stronger decrease in oil flow rate than in the variants with cyclic injection, in the variants with cyclic operation of the PPD system the highest indicators of accumulated oil production are achieved for a certain period.

Analysis of the implemented development system effectiveness, horizontal wells drilling and well interventions in the conditions of carbonate deposits of the Tournaisian tier of the Znamenskoye oil field

he paper analyzes the implemented system for the oil deposits of the Tournaisian tier of the Znamenskoye field development, as well as factors reducing its effectiveness, assessment of the features of the geological structure affecting oil production, and the development of proposals to improve the development system efficiency. It is noted that during the development of the field, the geological structure of the Tournaisian tier oil deposits has significantly changed because of the additional study of the development facility, the high efficiency of the use of horizontal wells has been confirmed. It shows an increase in the initial well flow rate and the specific accumulated oil production per meter of oil-saturated reservoir thickness, a decrease in the initial water content of well production, the growth rate of water content, a decrease in the accumulated oil-water factor for the first year of well operation, depending on the increase in the capacity of the bridge between the oil and water-saturated layers. Keywords: oil reserves production; bridge; oil recovery factor; oil-water factor; well.

Method of Geomechanical Parameter Determination and Volumetric Fracturing Factor Simulation under Highly Stochastic Geologic Conditions

In order to accurately predict geomechanical parameters of oil-bearing reservoirs and influencing factors of volumetric fracturing, a new method of geomechanical parameter prediction combining seismic inversion, well logging interpretation and production data is proposed in this paper. Herein, we present a structure model, petrophysical model and geomechanical model. Moreover, a three-dimensional geomechanical model of a typical reservoir was established and corrected using history matching. On this basis, a typical well model was established, 11 influencing factors of volume fracturing including formation parameters and fracturing parameters were analyzed and their impact were ranked, and the oil recovery rate and the accumulated oil production before and after optimal fracturing were compared. The results show that with respect to formation parameters, reservoir thickness is the main influencing factor; interlayer thickness and stress difference are the secondary influencing factors; and formation permeability, Young’s modulus and Poisson’s ratio are the weak influencing factors. For a pilot well of a typical reservoir, the optimized fracture increased production by 7 tons/day relative to traditional fracturing. After one year of production, the method increased production by 4 tons/day relative to traditional fracturing, showing great potential in similar oil reservoirs.

Experimental analysis of matrix moveable oil saturation in tight sandstone reservoirs of the south Ordos Basin, China

Tight oil reservoirs in the south Ordos Basin are characterized by fractured, heterogeneous oil-bearing strata (an oil saturation of less than 55% on average), normal pressure (0.8±) and extra-low permeability (less than 0.3 mD). In the Chang 8 tight sandstone reservoir in Honghe oilfield, micro- and nano-pores, especially those with a pore-throat radius of less than 1 μm, account for more than 90%. Fluid flow in the matrix is non-linear and crude oil flow rates are very low under normal pressure gradients. An improved understanding of oil mobility in a tight matrix is key to further development of normal-pressure tight-oil resources in the continental basin. In this study, constant-velocity and high-pressure mercury injection experiments were conducted using samples of typical tight sandstone cores obtained from the south of Ordos Basin. A new method for reconstructing the full-scale pore-throat distribution characteristics of tight sandstone reservoirs was established successfully, based on which multistage centrifugal tests, tests of low-pressure differential displacement of oil by water, and nuclear magnetic resonance tests were conducted in order to obtain the distribution characteristics of moveable fluid in different pores. The moveable oil saturation (MOS) and degree of oil recovery (i.e. ratio of accumulative oil production to producing geologic reserves) of the core samples under different differential pressures for displacement were determined. As for the tight oil reservoirs in the south Ordos Basin, the moveable fluids are mainly stored in sub-micron (0.10–0.5 μm) pores. For Type Ⅰ reservoirs (k > 0.1 mD), the volume percentage of moveable fluid in pores with a radius larger than 0.5 μm is relatively high (greater than 40%). The degree of oil recovery of water flooding serves as the basis for forecasting recoverable reserves for tight oil reservoirs. Recoverable reserves under water flooding, mainly occur in pores with a radius greater than 0.5 μm. The contribution of Type Ⅰ reserves to oil production is observed to be greater than 60%, and the degree of oil recovery reaches up to 17.1%. These results help improve our understanding on the evaluation and classification of Chang 8 tight sandstone reservoirs in Honghe oilfield and serve as theoretical basis for pilot tests to explore effective injection media and development methods to improve the matrix-driven pressure differences and displacement efficiency for oil.

Investigation on the asymmetric inter-fracture asynchronous huff-n-puff technology for the horizontal well group in the tight oil reservoir

Water huff-n-puff is one of the effective energy supplement methods for the development of tight oil reservoirs by horizontal wells. However, the oil production performance of water huff-n-puff severely decreases after several cycles. Available researches indicate that the inter-fracture asynchronous injection-production technology for the horizontal well is an efficient method for improving the oil production performance of water huff-n-puff. However, considering the object of the inter-fracture asynchronous huffn- puff is the single horizontal well, the study for a horizontal well group is less. Therefore, the asymmetric inter-fracture asynchronous huff-n-puff technology for the horizontal well group was investigated in this paper. The oil productions of the horizontal well group for different huff-n-puff modes were compared and analyzed first. After that, the oil recovery mechanisms of the asymmetric inter-fracture asynchronous huff-n-puff technology for the horizontal well group were revealed. Finally, the influence of operating parameters on the oil production of the horizontal well group for the asymmetric inter-fracture asynchronous huff-n-puff technology for the horizontal well group was studied by the numerical simulation method. The results show that compared with the water huff-n-puff, the accumulative oil productions for the asymmetric inter-fracture asynchronous huff-n-puff technology for the horizontal well group increased by 5134.8m3, and the increased amplitude is 36.86%. The imbibition, the inter-fracture displacement, and the inter-well displacement are the main oil recovery mechanisms of the asymmetric inter-fracture asynchronous huff-n-puff technology for the horizontal well group. The accumulative oil production of the horizontal well group for the asymmetric inter-fracture asynchronous huff-n-puff increases first, and then declines, finally tend to be stable with the increase of injection rate. Both the injection volume and the soaking time show a positive correlation with the accumulative oil production. The accumulative oil production of the horizontal well group decreases with the increase of production rate due to the aggravation of water channeling in the production stage. This work could provide certain theoretical guidance for the effective development of similar reservoirs by the horizontal well group.

Analysis of Enhanced Oil Recovery Technology in Extra-high Water Cut Period in Oilfield

Most onshore oil fields in China are in the later stage of development, and the water content is more than 90%, which increases the difficulty of remaining oil mining. In order to improve the oil production, it is necessary to develop a variety of oil recovery technologies, increase the oil field space pressure, weaken the oil viscosity, and improve the recovery factor. Taking L oilfield as an example, the paper briefly expounds the characteristics of extra-high water cut period, and on this basis, puts forward recovery technology, grasps development rules, and realizes technological innovation. The accumulative oil production reaches 2.32 million tons, and the recovery factor increases by 9%, thus providing reference for related workers.

Statistical modeling of oil reservoir life cycle

Based on statistical analysis, a method of stage-by-stage structuring and allocation of the boundaries of the stages of oil field development is proposed. The procedures for calculating the remaining recoverable reserves and the time to reach the maximum level of current oil production are given. Based on the values of accumulated oil production at the final stage of development, using the adaptive Kalman filter, forecasts of oil production are constructed in discrete time and estimates of the possibility of achieving design indicators with the existing development system are given. Keywords: Stage-to-stage structuring; Development stages; Forecast of recoverable reserves; Predicted oil production; Kalman filter.

Statistical modeling of oil reservoir life cycle

Based on statistical analysis, a method of stage-by-stage structuring and allocation of the boundaries of the stages of oil field development is proposed. The procedures for calculating the remaining recoverable reserves and the time to reach the maximum level of current oil production are given. Based on the values of accumulated oil production at the final stage of development, using the adaptive Kalman filter, forecasts of oil production are constructed in discrete time and estimates of the possibility of achieving design indicators with the existing development system are given. Keywords: Stage-to-stage structuring; Development stages; Forecast of recoverable reserves; Predicted oil production; Kalman filter.

Numerical Simulation of Low-Permeability Reservoirs with considering the Dynamic Boundary Layer Effect

Surface active components, salt component, and polar molecules in the fluid may adsorb on the solid surface and form the boundary layer during low-speed flow in a porous medium, which will influence the flowing law in the porous medium. Previous studies on flowing in low-permeability reservoirs mainly focus on the effects of the threshold pressure gradient. But few of them have considered the time-varying effect of the boundary layer thickness in solving the numerical simulation. The correlation among the boundary layer thickness and pressure gradient was established by regressing the experimental data of boundary thickness versus pressure. On this basis, the mathematical model of oil-water two-phase flow which involves influence of the boundary layer was constructed, and the comparative analysis of the development effect is performed. Results demonstrated that the boundary layer thickness is sensitive to the throat radius and pressure gradient, and the boundary layer thickness decreases dynamically with the increase of pressure gradient. The displacement velocity and accumulative oil production with boundary layer effect decrease when comparing with that without the boundary layer effect. Meanwhile, the boundary layer accelerates the breakthrough of water. With the reduction of production pressure difference, the difference between accumulative oil production with and without the boundary layer effect increases, which indicate that the dynamic effect of the boundary layer is intensified.

Study of a low-damage efficient-imbibition fracturing fluid without flowback used for low-pressure tight reservoirs

The oil production from the low-pressure tight reservoirs in China decreases sharply after fracturing under natural depletion. To supply the formation energy and displace oil through imbibition instead of flowback, a novel nanoparticle-enhanced supramolecular fracturing fluid (NESF) was developed. It consisted of 0.10 wt% hydrophobically modified hydroxypropyl guar (HMHPG), 1.00 wt% synthesized hydrophilic gemini surfactant (HGS), and 0.05 wt% hydrophobically fumed nanosilica (HNS). A series of experiments were conducted to characterize the molecular structure of HGS and evaluate the heat/shear resistance, rheological property, proppant suspension and transportation, formation damage, and imbibition efficiency of NESF. Finally, the oilfield practical application of NESF fracturing without flowback was carried out. The results showed that the heat resistance and the interfacial property of NESF were improved by HNS and HGS respectively. Besides the favorable common properties, a low oil permeability loss rate of 9.40%, a high fracture conductivity retainment rate of 95.11%, and a high imbibition recovery factor of 19.43% were realized by NESF. The accumulative oil production of the well stimulated by NESF without flowback was increased by 13.55% and the decline rate of oil production was reduced from 14.70% to 5.22% in the first 6 months.

Study of massive water huff-n-puff technique in tight oil field and its field application

Based on the characteristics of horizontal oil wells in tight reservoirs during their late stage, which are exploited by elastic drive of natural energy and stimulated by large-scale volume fracturing; the massive water huff-n-puff technique is proposed for the use of supplementing the energy of the depleted formations, which can effectively increase the productivity of single horizontal oil well in addition to its financial benefits. In this paper, the massive water huff-n-puff technique is defined and discussed from the following aspects of the mechanism, reservoir engineering, laboratory experiments and so forth. Additionally, comprehensive analyses of the advantages of applying this technique in the development of tight oil reservoirs are provided. By the studies of the pressure composition diagram and the definition of residual injection pressure (RIP) in reservoirs, a massive water huff-n-puff mathematical model was established and the critical parameters for water-flooding were calculated. Laboratory experiments of this technique have shown that it can induce a certain number of micro-fracture networks and its application in actual oilfields also shown positive results. The pilot tests have achieved remarkable increases in productivity and economic benefits. For example, the average daily oil production from a single well is increased by 4.5 t/d (0.8 → 5.3 t/d), the formation pressure has increased by 9.3 MPa (6.9 → 16.2 MPa), accumulated oil production has reached 1,987t, and its input-output ratio has shown an enhancement in the range of 1.00:1.74–1.00:4.06. The research results of this technique provide a new way and an important model for efficient development of horizontal wells in tight oil reservoirs.

MULTIFACTORIAL STATISTICAL ANALYSIS OF FACTORS INFLUENCING THE EFFICIENCY OF ACID FRACTURING

Background Highly productive terrigenous strata of Western Bashkortostan, which contain residual oil reserves, have been largely developed, and they reduce the rate of oil production, increase water cut in well production, which leads to an increase in the oil production cost and contributes to an increase in the stock of wells with difficult operating conditions. All these factors make it necessary to carry out geological and technical measures at the wells in order to restore the production wells capabilities. The statistical analysis use in assessing the reasons for the decline in the success of geological and technical measures allows us to establish the level of technological processes influence on the acid fracturing effectiveness, and thereby contribute to its optimization, as well as to predict its effectiveness. Aims and Objectives Determination of the following statistical dependencies: o the value of additionally produced as a result of acid fracturing of oil from the total accumulated production in the well; o the effect time of the total well time; o an increase in the productivity coefficient of the well from a number of geological, physical, and energetic characteristics of the formations and technological parameters of acid fracturing. Results As a result of the multifactorial analysis of the well and reservoir geological, technical, technological and energy parameters, affecting the acid fracturing efficiency, it was established that when selecting candidate wells, it is necessary to choose wells with pressure in the drainage zone lower than 30 % of the initial reservoir pressure. It was revealed that the optimal value of the dimensionless conductivity coefficient is 4. The salt-acid solution optimal specific consumption for the conditions of the Tournaisian stage of oil fields in Western Bashkortostan is 2.9-3.3 m3/m. The water cut of well production should not be more than 50 %, since a further increase in water cut leads to a significant reduction in the ratio of cumulative production as a result of acid fracturing to total cumulative oil production. The distance to the oil-water contact should be at least 15-20 m, since with a decrease in this distance, the ratio of production accumulated as a result of acid fracturing to the total accumulated oil production due to a possible breakthrough of water decreases.

A Numerical Investigation of Low-Salinity Waterflooding Capability to Enhanced Oil Recovery

Low-salinity water flooding (LSWF) is one of techniques that can be used to improve oil production and has gained a significant attention in these days because of its advantages over conventional water flooding and chemical flooding. Even though many mechanisms have been recommended on an extra oil recovery achieved using LSWF process, the principle fundamental of the mechanism is still not fully understood. This research paper investigates the potential of oil recovery in an onshore sandstone reservoir using LSWF. A field-scale three–dimensional reservoir model has been developed via CMG’s GEM compositional simulator where the model validated against a real production field data that were in good agreement with a deviation value of 8%. The primary mechanism of LSWF has been identified by providing incremental oil recovery due to a multi-component ion exchange mechanism that causes wettability alteration of reservoir rock from oil-wet to water-wet. The sensitivity study showed that LSWF provides a higher accumulative oil production compared to conventional high salinity water injection with 13.5 and 12 MMSTB. Moreover, the early time of low saline brine injection can provide a maximum oil recovery up to 71%. Therefore, implementing this scenario immediately after the primary recovery, it provides production benefits in both secondary and tertiary method. The oil recover factor increased to 75.5% with the increasing of brine injection rate up to an optimum value of 5320 bbl/d. A reservoir temperature also influenced the ion exchange wettability alteration during LSWF in which as the temperature increasing enhances the oil recovery. Therefore, a high temperature sandstone reservoir will be a potential candidate for LSWF.

Burial and exhumation history of the Labrador-Newfoundland margin: first observations

The continental shelf of Labrador and Newfoundland has a long history of hydrocarbon exploration, and the accumulated oil production from the northern Grand Banks exceeds one billion barrels (Fig.1). The Canada-Newfoundland & Labrador Offshore Petroleum Board (www.cnlopb.ca) awarded several new licenses on the northern Grand Banks in 2015 and announced licensing rounds for the Labrador Sea region in the coming years.