Slug Size Research Articles

An artificial neural network model for predicting the recovery performance of surfactant polymer floods

Abstract A supervised feed-forward back-propagation neural network model has been developed for estimating the recovery performance of a reservoir subjected to a surfactant–polymer (SP) flood. The optimal network paradigm has been designed by conducting extensive experimentation on the proper number of hidden layers, and of neurons in each of these layers. The optimal multi-layered network topology consists of an 18-neuron input layer, three 11-neuron hidden layers, and a four-neuron output layer. The network input consists of 18 dimensionless groups that critically dominate the displacement efficiency of SP floods. These groups account for the effects of surfactant slug size, polymer slug size, surfactant concentration, surfactant/oil bank mobility ratio, polymer/surfactant mobility ratio, surfactant and polymer adsorption, interfacial tension, reservoir heterogeneity, relative permeabilities, capillary pressure, waterflood residual saturations, the optimal salinity in the three-phase region, gravity, and rock wettability. Principal component analysis indicated that all of these 18 dimensionless groups were essential for scaling SP floods. The network output consists of the oil recovery at 0.75, 1.5, and 2.25 pore volumes injected (PVI), along with estimates of the breakthrough dimensionless time. The network model has been trained on a data set consisting of 499 simulations, generated using a three-dimensional compositional chemical flood simulator. Tertiary chemical floods constitute 90% of the simulation runs. The rest of the simulation cases are secondary chemical injections. The optimal network architecture was able to estimate back the oil recovery from the training set within 1.5% average absolute error. The ANN model was able to predict the oil recovery for a blind-test data-set of 125 simulated field cases within approximately 3% average absolute error. With these remarkable results, the ANN model outperformed the non-linear multivariate models available in the literature. Compared to using extensive numerical modeling based on the detailed knowledge of the oil reservoir, the use of the introduced ANN model saves significant amount of time needed for the performance prediction of surfactant–polymer floods. The ANN model may, therefore, be used as a valuable tool for the preliminary assessment of oil reservoirs with respect to their suitability for surfactant–polymer flood.

Synthesis of hexadecylbenzene sulfonate and its application in alkali-free flooding systems

Hexadecylbenzene sulfonate was synthesized using aluminum trichloride catalyzed Friedel–Crafts reaction with hexadecyl linear internal olefin to benzene, sulfonated by chlorosulfonic acid, and neutralized with sodium hydroxide. The structure of the synthesized hexadecylbenzene sulfonate was characterized by infrared spectroscopy and mass spectroscopy. Surfactant mixtures were formulated by the synthesized hexadecylbenzene sulfonate and Kelamayi petroleum sulfonate. The results showed that the surfactant mixtures could reduce the interfacial tension to ultra-low values in the presence as well as the absence of polymer, at a very low concentration. The surfactant/polymer systems had a good thermal stability. The recovery factor was 59.85 % of original oil in place when the surfactant/polymer slug size was 0.3 pore volume of the core, compared with 45.59 % in case of water flood.

Pressure Maintenance and Improving Oil Recovery by Means of Immiscible Water-Alternating-CO2 Processes in Thin Heavy-Oil Reservoirs

Summary Techniques have been developed to experimentally and numerically evaluate performance of water-alternating-CO2 processes in thin heavy-oil reservoirs for pressure maintenance and improving oil recovery. Experimentally, a 3D physical model consisting of three horizontal wells and five vertical wells is used to evaluate the performance of water-alternating-CO2 processes. Two well configurations have been designed to examine their effects on heavy-oil recovery. The corresponding initial oil saturation, oil-production rate, water cut, oil recovery, and residual-oil-saturation (ROS) distribution are examined under various operating conditions. Subsequently, numerical simulation is performed to match the experimental measurements and optimize the operating parameters (e.g., slug size and water/CO2 ratio). The incremental oil recoveries of 12.4 and 8.9% through three water-alternating-CO2 cycles are experimentally achieved for the aforementioned two well configurations, respectively. The excellent agreement between the measured and simulated cumulative oil production indicates that the displacement mechanisms governing water-alternating-CO2 processes have been numerically simulated and matched. It has been shown that water-alternating-CO2 processes implemented with horizontal wells can be optimized to significantly improve performance of pressure maintenance and oil recovery in thin heavy-oil reservoirs. Although well configuration imposes a dominant impact on oil recovery, the water-alternating-gas (WAG) ratios of 0.75 and 1.00 are found to be the optimum values for Scenarios 1 and 2, respectively.

Experimental Study on the Properties and Displacement Effects of Polymer Surfactant Solution

Based on the characteristics of oil reservoirs and the requirements of further enhancing oil recovery at high water cut stage of Pubei Oilfield, the displacement performance of polymer surfactant is evaluated. Reasonable injection parameters and oil displacement effects after water flooding are also researched. Compared with conventional polymer with intermediate molecular weight, polymer surfactant has the properties of higher viscosity at low concentration condition and lower interfacial tension. Laboratory experiments indicate that the displacement effect of polymer surfactant is much better than that of conventional polymer at a slug size of 0.57 PV. The oil recovery of polymer surfactant increases by more than 10% after water flooding. Considering the actual situation of low‐permeability of Pubei Oilfield reservoirs, the system viscosity of 30 mPa·s is chosen. The corresponding concentration of Type III polymer surfactant is 600 mg/L and the injected slug is 0.57 PV and the oil recovery can be increased by 11.69%.

Design Considerations of Waterflood Conformance Control With Temperature-Triggered, Low-Viscosity Submicron Polymer

Summary In waterfloods, the existence of highly conductive thief zones causes poor volumetric sweep efficiency, resulting in early breakthrough and excessive production of water. A conventional strategy of redirecting injection by closing off perforations yields short-term benefits because diversion occurs near the wellbore. As an alternative, temperature-triggered submicron polymers with low viscosity (popping agents), which give an opportunity for conformance control deep in the reservoir, have been introduced in recent years. This technology aids conformance control by plugging the high-permeability zones and diverting the fluid to the unswept portion of the reservoir. Understanding the critical parameters that lead to a successful treatment and accurate determination of the slug size are two important criteria for a technically and economically successful treatment. In this study, we first investigate the effect of different parameters on the success of a conformance control treatment. A comprehensive design-of-experiments (DOE) study resolves the effects (and combined effects) of kv/kh, treatment fluid concentration, thief-zone to matrix-permeability ratio, mobility ratio, and location of the placement in the reservoir. Next, a methodology is developed for accurate determination of the conformance slug size. The method is built on the temporal moment and residence time distribution analysis (RTDA) of interwell tracers. Dynamic flow- and storage-capacity curves are used to identify the optimum slug size. 3D thermal computer simulations show that thief-zone to matrix-permeability ratio and placement location of the polymer are the most important parameters that affect the success of a treatment. The most desirable setting is placement of the polymer deep in the reservoir, closer to the producer within high kv/kh reservoirs. Furthermore, the computer simulations confirm the power of the new technique for optimal slug-size determination. This new technique can avoid underestimation of the volume that must be treated, which is critical for the success of a treatment.

Potential of alkaline flooding to enhance heavy oil recovery through water-in-oil emulsification

Alkaline flooding has great potential for enhancing the recovery of heavy oil, especially for reservoirs in which thermal methods are not suitable. In this study, alkaline flooding tests were performed in micromodels and sandpacks to investigate the microscopic displacement mechanisms for enhancing heavy oil recovery and the effect of the injection parameters on displacement efficiency. The micromodel tests indicate that the penetration of the alkaline solution into the crude oil and the subsequent formation of a water-in-oil (W/O) emulsion reduce the mobility of the water phase and divert the injected water into the unswept region, thereby improving the sweep efficiency. The sandpack flood results show that the tertiary oil recovery can reach about 20% of the initial oil in place (IOIP) using 1.0% NaOH, and the tertiary oil recovery has been found to increase as the alkaline concentration increases. However, there is an optimum slug size and injection rate at which the highest tertiary oil recovery can be obtained during the alkaline flooding process. Continuous alkaline injection can provide a higher tertiary oil recovery compared with a cyclic alkaline injection pattern. These results show that the alkaline flooding, if properly designed and controlled, can lead to enhanced heavy oil recovery through the water-in-oil emulsification.

Simulation of Surfactant Based Enhanced Oil Recovery

Surfactant flooding is an important process for enhanced oil recovery. A substantial amount of remaining oil resides in reservoirs especially in carbonate oil reservoirs that have low primary and water-flood oil recovery. Most of the surfactant flooding studies to date has been performed in water-wet sandstone reservoirs. As a result, the effects of heterogeneity and wettability of carbonates on surfactant flooding efficiency are fairly unknown. The purpose of this simulation study was to determine the effects of wettability and wettability alteration on Dodecylbenzene Sulfonate surfactant flooding in carbonate reservoirs. This study used the multi-phase, multi-component, surfactant flooding simulator called UTCHEM. The base case results showed that additional 27.8% of oil recovered after water-flooding process. Sensitivity analyses of key parameters such as chemical slug size and concentrations, salinity, reservoir heterogeneity and surfactant adsorption were performed to optimize a surfactant design for a mixed-wet dolomite reservoir. The study was then extended to simulating wettability alteration during the field scale surfactant flood. The results of modeling the wettability alteration showed that significant differences in injectivity and oil recovery are caused by the changes in the mobility of the injected fluid. As the use of surfactant flooding spreads into the reservoir especially oil-wet and mixed-wet reservoirs, the importance of surfactant-based wettability alteration will become important.

Orthogonal Experimental Design on the Program of CO<sub>2</sub> Displacement

Combining module PVTi with E300 in ECLIPSE, we found the 3D and three phases simulating module of special low permeability reservoirs in YSL Oilfield. On the basis of history matching, considering gas injection volume, slug size, gas/water ratio, the speeding of gas injection, injection rate of sequent water flooding in water alternating gas, taking the volume of increasing oil and oil-draining rate as evaluation criterion we proceed orthogonal test design according to the principle orthogonal experimental design. By means of intuitive analysis and variance analysis to the test results, getting the primary and secondary orders that injection parameters effect evaluation criterion and optimizing best combination scheme of water alternating gas injection parameters for offering theoretical direction and technical support to water alternating gas injection parameters optimization in spot CO2 displacement.

Study on Alkaline Mass Transfer Regularity with Dissolution in Porous Media

Inducting dissolution speed constant and multistage reaction series to the alkaline solution transmission equation, this article established the alkaline solution transmission equation with multistage reaction dynamics in the porous media of stratum mineral and calculated one-dimensional alkaline solution concentration distribution. Experimental results verified the correctness of transmission equation, moreover, it further analyzed the alkaline solution regularity in the porous media. The model will be used to predict alkali loss, optimize alkaline solution concentration and slug size, thereby alkaline waterflooding or combination drive can obtain better displacement characteristics and improve the oil recovery.

Simulation of Surfactant Based Enhanced Oil Recovery

Surfactant flooding is an important process for enhanced oil recovery. A substantial amount of remaining oil resides in reservoirs especially in carbonate oil reservoirs that have low primary and water-flood oil recovery. Most of the surfactant flooding studies to date has been performed in water-wet sandstone reservoirs. As a result, the effects of heterogeneity and wettability of carbonates on surfactant flooding efficiency are fairly unknown. The purpose of this simulation study was to determine the effects of wettability and wettability alteration on Dodecylbenzene Sulfonate surfactant flooding in carbonate reservoirs. This study used the multi-phase, multi-component, surfactant flooding simulator called UTCHEM. The base case results showed that additional 27.8% of oil recovered after water-flooding process. Sensitivity analyses of key parameters such as chemical slug size and concentrations, salinity, reservoir heterogeneity and surfactant adsorption were performed to optimize a surfactant design for a mixed-wet dolomite reservoir. The study was then extended to simulating wettability alteration during the field scale surfactant flood. The results of modeling the wettability alteration showed that significant differences in injectivity and oil recovery are caused by the changes in the mobility of the injected fluid. As the use of surfactant flooding spreads into the reservoir especially oil-wet and mixed-wet reservoirs, the importance of surfactant-based wettability alteration will become important.

The Experimental Investigation of Nitrogen and Carbon Dioxide Water-alternating-gas Injection in a Carbonate Reservoir

Floods were conducted using rock–fluid systems consisting of carbonate cores from Binak reservoir, which is located in southwest of Iran, oil and brine. The coreflood protocol consisted of a series of steps including brine saturation, absolute permeability determination, flooding with oil to initial oil saturation, endpoint oil permeability determination, and, finally, nitrogen and carbon dioxide water-alternating-gas (WAG) injections. The effect of slug size on oil recovery was investigated using immiscible nitrogen (N2) WAG injection and the amount of oil recovered was compared with continuous injection of N2. Experimental results show that ultimate oil recovery is not very sensitive to changing the slug sizes for N2 WAG injection, although the slug size of 0.15 pore volume (PV) injection is better than others. As less PV is injected, a higher oil production rate is achieved. Also, N2 WAG flood appeared to be better in performance than continuous gas injection (CGI) of nitrogen. Carbon dioxide (CO2) injection was performed in three modes, including CGI, WAG injection, and hybrid WAG. Experimental results show that for optimization of oil recovery in CO2 floods, a continuous gas slug of 0.4–0.5 PV followed by 1:1 WAG needs to be injected.

Segmented flow synthesis of Ag nanoparticles in spiral microreactor: Role of continuous and dispersed phase

This work focuses on understanding the effect of segmented flow on the nanoparticle size distribution in a unidirectionally expanding spiral microreactor, where secondary flows are prevalent in the absence of segmentation. Stearic acid sophorolipid reduced/capped Ag NPs were synthesized in the aqueous phase and air or kerosene was used as inert phases for creating the gas–liquid and liquid–liquid segmented flow, respectively. While, in one case the reactant phase is in the form of dispersed phase slugs, in the other case it is in the form of continuous phase, each exhibiting a different behavior. The slug sizes and the slip velocity, both of which govern the nature of internal mixing in the reactant phase slug controlled the nanoparticle size distribution. This observation was consistent for both, gas–liquid and liquid–liquid segmented flows. The micromixer having smaller orifice diameter yielded smaller slugs and also a narrow particle size distribution. In general, the particle sizes were much smaller for gas–liquid flow rather than for liquid–liquid flow. Because of the unidirectionally expanding spiral geometry of the channel, at any given condition, unsteady behavior of slugs due to continuously varying radius of curvature results in variation in the slip velocity along the length of microchannel. This effect was seen to further narrow the particle size distribution than alone by the segmented flow.

Thermally Active Polymer To Improve Sweep Efficiency of Waterfloods: Simulation and Pilot Design Approaches

Summary A common problem in many waterflooded oil reservoirs is early water breakthrough with high water cut through highly conductive thief zones. Thermally active polymer (TAP), which is an expandable submicron particulate of low viscosity, has been successfully used as an in-depth conformance to improve sweep efficiency of waterfloods. This paper describes the workflow to evaluate technical feasibility of this conformance technology for proper pilot-project designs supported with detailed simulation studies. Two simulation approaches have been developed to model properties of this polymer and its interaction with reservoir rock. Both methods include temperature-triggered viscosification and adsorption/retention effects. Temperature profile in the reservoir is modeled by energy balance to accurately place this polymer at the optimum location in the thief zone. The first method considers a single chemical component in the water phase. The second method is based on chemical reactions of multiple chemical components. Both simulation approaches are compared and discussed. Results show that temperature-triggered polymers can increase oil recovery by viscosification and chemical adsorption/retention, which reduces thief-zone permeability and diverts flow into unswept zones. Sensitivity analyses suggest that ultimate oil recovery and conformance control depend on the thief-zone temperature, vertical-to the horizontal-permeability ratio (Kv/Kh), thief-zone vertical location, injection concentration and slug size, oil viscosity, and chemical adsorption and its reversibility, among other factors. For high-flow-capacity thief zones and mobility ratios higher than 10, oil recoveries can be improved by increasing chemical concentration or slug size of treatments, or both. Reservoirs with low Kv/Kh (< 0.1) and high permeability contrast generally shows faster incremental recoveries than reservoirs with high Kv/Kh and strong water segregation. The presented workflow is currently used to perform in-depth conformance treatment designs in onshore and offshore fields and can be used as a reference tool to evaluate benefits of the TAP in waterflooded oil reservoirs.

The Potential of a Surfactant/Polymer Flood in a Middle Eastern Reservoir

An integrated full-field reservoir simulation study has been performed to determine the reservoir management and production strategies in a mature sandstone reservoir. The reservoir is a candidate for an enhanced oil recovery process or otherwise subject to abandonment. Based on its charateristics, the reservoir was found to be most suited for a surfactant/polymer (SP) flood. The study started with a large data gathering and the building of a full-field three-dimensional geological model. Subsequently, a full field simulation model was built and used to history match the water flood. The history match of the water flood emphasizes the areas with remaining high oil saturations, establishes the initial condition of the reservoir for an SP flood, and generates a forecast of reserves for continued water flood operations. A sector model was constructed from the full field model and then used to study different design parameters to maximize the project profitability from the SP flood. An economic model, based on the estimated recovery, residual oil in-place, oil price, and operating costs, has been implemented in order to optimize the project profitability. The study resulted in the selection of surfactant and polymer concentrations and slug size that yielded the best economic returns when applied in this reservoir. The study shows that, in today’s oil prices, surfactant/polymer flood when applied in this reservoir has increased the ultimate oil recovery and provide a significant financial returns.

Chemical flooding optimisation using the experimental design approach and response surface methodology

One of the most effective methods of enhanced oil recovery is chemical flooding. This process can significantly increase the oil recovery; however, it involves high risks and uncertainties. We determined the optimal chemical flooding design, which is the maximum of the net present value (NPV), using the UT_IRSP platform and an in-house chemical flooding simulator, as well as the application of experimental design and respond surface for a particular oil reservoir. Surfactant and polymer mass, kv/kh ratio, salinity of polymer drive, and salinity of post-water flood were variables used in our optimisation calculations. We found that the interaction between the surfactant concentration and surfactant slug size is the most important term affecting the NPV. Therefore, the oil recovery was improved by 8% of the original oil in place (OOIP) in a designed chemical flooding case scenario. Also, the NPV with tax and royalty increased notably from 6.42 MM USD to 8.08 MM USD for the 50 USD/bbl of oil price.

Present Status of Research and Application of Chemical Combination Flooding Technique and its Future

Chemical combination flooding technique is one of EOR techniques. The current status of chemical combination flooding including EOR mechanism, formula study, field test and application have been introduced and discussed. The problems met in field tests and future development trend of chemical combination flooding are directed. Synergistic effect among alkali, surfactant and polymer in ASP combination flooding, can improve both displacing efficiency and swept efficiency due to the increase of viscosity of displacing liquid and decrease in interfacial tension between oil and water. Emulsion ability of the chemical combination system can also improve the displacing efficiency. In addition, viscoelasticity of the combination system is also beneficial to improve the displacing efficiency. There are two main research tendencies for the formula system of chemical combination flooding. One is the high concentration small slug size system leaded by U.S., which can get high oil recovery but the cost is high. The other is a low concentration large slug size system leaded by China, which has good results and relatively low cost. With recent development of new polymers and surfactants, the chemical combination flooding has been will be widely used in different reservoirs. Pilot tests of ASP flooding in China have increased the oil recovery significantly. And such process has been extended to industrial tests and application. A serial of technologies has formed during ASP flooding field tests. Two main problems are shorter pump-checking period and higher cost of produced liquid handing. In order to avoid the negative effect of alkali, SP flooding pilot tests have been deployed. The general trend of chemical combination flooding technique is changing from strong-alkali ASP flooding to weak-alkali ASP flooding and alkali-free SP flooding. The application target reservoirs have extended from integral sandstone reservoirs to conglomerate reservoirs, complicated fault block reservoirs and carbonate reservoirs, from low temperature and low salinity reservoirs to high temperature and high salinity reservoirs.

Optimal control of polymer flooding based on mixed-integer iterative dynamic programming

Polymer flooding is one of the most important technologies for enhanced oil recovery. In this article, a mixed-integer optimal control model of distributed parameter systems (DPS) for the injection strategies is established, which involves the performance index as maximum of the profit, the governing equations as the fluid flow equations of polymer flooding and some inequalities constraints, such as polymer concentration and injection amount limitation. The control variables are the volume size, the injection concentration of each slug and the terminal flooding time. For the constant injection rate, the slug size is determined by the integer time stage length, and thus the integer variables are introduced in the DPS. To cope with the optimal control problem (OCP) of this DPS, a mixed-integer iterative dynamic programming incorporating a special truncation procedure to handle integer restrictions on stage lengths is proposed. First, the OCP with variable time stage lengths is transformed into a fixed time stage problem by introducing a normalised time variable. Then, the optimisation procedure is carried out at each stage and preceded backwards in a systematic way. Finally, the numerical results of an example illustrate the effectiveness of the proposed method.

Research and Application of Air Foam Flooding in Longdong Jurassic Reservoir

Longdong Jurassic reservoir is a typical severe heterogeneous reservoir. Water flooding in this area is ineffective owing to water breakthrough and water flush. Laboratory experiments and field application of air foam flooding are described in this paper. Firstly, the air foam agent formula that suitable for Longdong Jurassic reservoir is selected as 0.5wt%HD-6 + 0.15wt%HD-Y by studying the foaming ability, stability and interfacial tension between oil and surfactant solution. The oil displacement results indicate that air foam flooding is more effective than the usage of surfactant waterflooding and air injection considering the amount of acquired recovery factor. In addition, process parameters of air foam flooding are determined by core flooding tests. The gas/liquid ratio is set to 3:1 and the chemical slug size is set to 0.9PV. Based on the experiments, air foam flooding is applied in Maling Block, the performance indicates that this technique can increase injection pressure, improve the injection profile of reservoir, decrease the water cut and improve the oil production.

Analysis of Factors on Nan Pu Oilfield’s Weak Gel Flooding

There are lots of factors effect on weak gel flooding.This paper based on the conceptual model by changing the model parameters and using orthogonal design to analyze the effects of different factors on weak gel flooding. The descending order of influence is slug size, flooding time, oil-water viscosity ratio, permeability range, concentration of polymer, slug combination and polymer-cross linker ratio.

Evaluation of oil foam as a displacing phase to improve oil recovery: A laboratory study

The objective of this work is to investigate the possibility of considering oil foams for practical use in the recovery of oil. To achieve this objective a multifunction laboratory setup was designed to provide capillary tube-foam viscosity measurements, selective core configuration, selective foam generation scheme, and good control of gas injection-pressure and liquid injection-rate. The porous medium was represented by a 2 ft × 2 in. cylindrical Berea sandstone core with absolute permeability of 139.6 md and porosity of 23.1%. Kerosene (viscosity of 1.458 cp) and Nitrogen (specific gravity of 0.9672) were used as the liquid and gas components of the oil foam, respectively. A surfactant with code name FC-432 was used as foaming agent at a concentration of 1% by volume. The effects of imposed pressure differential, slug size of surfactant solution, and gravity on oil displacement by internally-generated foam scheme were investigated. The displacement of oil by externally generated foam was tested for three foam qualities of 70, 80, and 90% under imposed pressure differential of 15 psia. Gas drive and water flood tests were conducted for comparison purposes. Injection pressure in all tests was near 830 psia. The results of this work revealed that oil foams behave as non-Newtonian fluids with low yield stress and that their plastic viscosities increase with increased foam quality. Oil recoveries by oil foam displacement were significantly higher than those observed in gas drive and water drive tests. Vertical core configuration was found to yield higher oil recoveries than horizontal core configuration. Also higher oil recoveries were generally associated with lower imposed pressure drops, lower foam qualities, and larger slug size of surfactant solution. The mechanism of foam flow in the core was deduced from gas breakthrough, relative permeability concepts, and capillary tube model. A new iterative scheme of calculations is proposed to determine average foam saturation inside the core.