Cold Water Flooding Research Articles

Study on low-heat synergistic chemical profile control and flooding technology in Bohai Oilfield

Introduction: Through the combination of hot water and chemical agent, the low-heat synergistic chemical profile control and flooding technology can not only reduce the risks of sand production and string damage caused by high-temperature thermal recovery technology, but also further improve the recovery factor on the basis of hot water flooding.Methods: Based on laboratory testing, the synergism mechanism of thermal energy and chemical agent is studied.Results: The research results showed that in the near wellbore zone of the injection well, crude oil viscosity reduction mainly relies on thermal energy, and chemical agents assist in improving the water oil mobility ratio and reducing the risk of cross flow. After entering the deep formation, due to the decrease in temperature, the thermal energy effect is weakened, but the chemical agents still aggregate at the oil-water interface and continue to act on heavy oil to reduce viscosity. The higher the temperature, the greater the role of heat energy, and the weaker the role of chemical agents. The higher the injection concentration of chemical agent, the more obvious the leading role of chemistry. Based on the comprehensive evaluation index, the optimized temperature is 80°C and the injection concentration is 1500 mg/L. The scheme study of Bohai L Oilfield shows that compared with cold water flooding, hot water flooding can only improve oil recovery by 1.2 percentage points, and low heat collaborative chemical profile control flooding technology can further improve oil recovery by 4.7 percentage points on the basis of hot water flooding, with obvious oil increase effect.Conclusion: It is suggested that Bohai L Oilfield should apply low-heat coordinated chemical profile control and flooding technology to improve the development effect of the oilfield, and provide new technical ideas for safe and economic development of offshore heavy oil.

Cold water-flooding in a heterogeneous high-pour-point oil reservoir using computerized tomography scanning: Characteristics of flow channel and trapped oil distribution

There are relatively few studies that consider the influence of reservoir heterogeneity on reservoir wax deposition. This study conducts a computerized tomography scan to study the flow channels, heavy component retention, displacement efficiency, and trapped oil distribution in a high-pour point oil reservoir with a positive sedimentary rhythm under various water injection temperatures. This study greatly improves the understanding of the wax deposition influences on the flow channel. Three displacement models are proposed: water-flooding breakthrough model (49.5 °C), approximate-equilibrium piston-like displacement model (54.5 °C/59.5 °C), and non-equilibrium piston-like displacement model (64.5 °C). When the injection temperature is lower than the wax appearance temperature (59.5 °C), an elliptical wax deposition is formed at the inlet, the most serious deposition is in the middle-permeability layer. A wax deposition barrier is formed away from the inlet, and constrains the downward movement trend of the water injected above. Therefore, the moderate wax precipitation will improve the oil recovery from the top low-permeability layer. However, the heterogeneity in the spaces and strength of the barrier result in the oil recovery from the 100 mD layer at 59.5 °C begin higher than that at 54.5 °C; moreover, at 59.5 °C, the recovery at the inlet is better than that at the outlet. The vortex phenomenon increases the oil recovery from wax deposition area in the bottom layer at the inlet. The heavy component retention is significant, and the oil recovery decreases with decreasing injection temperature. After flooding, the formation mechanisms of the trapped oil include wax deposition, weak water washing, and reservoir sedimentary rhythms. The research results provide initial insights for the evaluation of cold damage.

Technical and economic feasibility of a novel heavy oil recovery method: Geothermal energy assisted heavy oil recovery

Conventional hot water flooding generally has disadvantages of high energy consumption and large capital expenses. To improve the economy of hot water flooding, a novel geothermal energy assisted heavy oil recovery method is presented. To validate this idea, a numerical simulation study is conducted to analyze the performance of the heat exchange well and heavy oil recovery process. Furthermore, the new method and conventional hot water flooding are compared to examine the economic feasibility of this new method based on the financial net present value. Finally, factors that may affect the feasibility of this new method are discussed. The simulation results show that compared with cold water flooding, the new method can increase heavy oil recovery by more than 7%. Moreover, the financial net present values of the new method at different oil prices all surpass those of the conventional water flooding, and thus the new method proposed is feasible both technically and economically. The analysis on the factors affecting the feasibility reveals that the critical oil price (the oil price when the financial net present value equals 0) of the new method decreases with increasing heavy oil reservoir thickness, decreasing oil viscosity, permeability variation coefficient and initial reservoir pressure.

Study on the optimal development method for offshore buried hill fractured reservoirs

In order to understand the percolation mechanism and development regulation in offshore buried hill fractured reservoir, similarity criteria of physical simulation on water flooding in the fractured reservoirs were established by using similarity and flow theory. Based on the similarity theory and Warren–Root model, a large-scale (1 m × 1 m × 0.5 m) physical similarity model was built. By conducting the similar physical experiments, the behavior and mechanism of fluid flow in the reservoir in different development modes were studied, together with the optimal development program selected. The physical simulation results show that the stereoscopic staggered horizontal well pattern can give full play to the function of oil–water gravitational differentiation and reduce the rising rate of water cut. Flooding mechanisms vary from mode to mode: The sweep efficiency of cold water flooding is higher, whereas the oil displacement efficiency in the fracture and oil recovery in the matrix are lower in the affected area. The hot water flooding can improve the oil–water flow ratio of the mainstream line, reduce the seepage resistance, and improve the oil displacement efficiency in the fracture and the oil recovery of the matrix in the area. However, due to poor heat transfer efficiency, the difference of seepage resistance between the mainstream line and other regional increases results in decreased sweep efficiency. Surfactant flooding reduces oil–water interfacial tension and improves flooding efficiency in the area, yet degenerates oil recovery for the matrix.

EM Heating-Stimulated Water Flooding for Medium–Heavy Oil Recovery

We report a study of heavy oil recovery by combined water flooding and electromagnetic (EM) heating at a frequency of 2.45 GHz used in domestic microwave ovens. A mathematical model describing this process was developed. Model equations were solved, and the solution is presented in an integral form for the one-dimensional case. Experiments consisting of water injection into Bentheimer sandstone cores, either fully water saturated or containing a model heavy oil, were also conducted, with and without EM heating. Model prediction was found to be in rather good agreement with experiments. EM energy was efficiently absorbed by water and, under dynamic conditions, was transported deep into the porous medium. The amount of EM energy absorbed increases with water saturation. Oil recovery by water flooding combined with EM heating was up to $$37.0\%$$ larger than for cold water flooding. These observations indicate that EM heating induces an overall improvement in the mobility ratio between the displacing water and the displaced heavy oil.

Hot water flooding and cold water flooding in heavy oil reservoirs

ABSTRACTMurphy Oil’s Seal asset in the Peace River Oil Sands region in North West Alberta, Canada, has a remarkable capacity for implementation of Enhanced Oil Recovery (EOR) processes. Some wells in Seal have shown strong historical production due to excellent permeability and the foamy solution gas drive mechanism. The reservoir characteristics in this portion are highly variable where determining the most suitable EOR method is very challenging. Two of the potential EOR candidates which have been evaluated for this portion include conventional cold waterflooding and hot waterflooding. Results of EOR core analysis, logging, detailed seismic and petrophysical studies, and history-matched reservoir simulation and forecast indicate that cold waterflooding outperforms hot waterflooding. This is surprising as hot waterflooding is believed to outperform cold waterflooding in most medium heavy oil reservoirs.

An evaluation of enhanced oil recovery strategies for a heavy oil reservoir after cold production with sand

Cold heavy oil production with sand (CHOPS) is the process of choice for unconsolidated heavy oil reservoirs with relatively high gas content. The key challenge of CHOPS is that the recovery factor tends to be between 5% and 15%, implying that the majority of the oil remains in the ground after the process is rendered uneconomic. Continued cold production (without sands) is not productive for a post-CHOPS reservoir because of the low oil saturation and depleted reservoir pressure in the wormhole regions. There is a need to develop viable recovery processes for post-CHOPS reservoirs. Here, different follow-up processes are examined for a post-CHOPS heavy oil reservoir. In post-CHOPS cold water flooding, severe water channeling is ineffective at displacing high viscosity heavy oil. Hot water flooding improves the sweep efficiency and produces more oil compared with cold water flooding. However, the swept region is limited to the domain between the neighboring wormhole networks, and the energy efficiency of the process is relatively poor. Compared with the hot water flooding case, steam flooding achieves higher oil production rates and lower water use. A cyclic steam stimulation strategy achieves the best performance regarding oil production rates and water usage. Based on our results, it is observed that thermally based techniques alone are not capable to recover the oil economically for post-CHOPS reservoirs. However, it is suggested that techniques with combined use of thermal energy and solvent could potentially yield efficient oil recovery methods for these reservoirs. Copyright © 2015 John Wiley & Sons, Ltd.

Numerical simulation of paraffin wax deposition in waxy crude oil reservoir with cold water flooding

The waxy crude oil translates single-phase liquid into two-phase solid–liquid due to paraffin wax deposition, as the temperature of injection water is below wax appearance temperature. The precipitating paraffin wax in the pores affects oil production due to reduction of porosity and permeability. In this paper, a numerical simulation model was established by establishing porous physical model with irreducible water and waxy crude oil under original reservoir condition, introducing a phase transformation equation and combining the mathematical model of a two-phase oil–water seepage field. Several typical characteristics of cooling damage were obtained. The worst cooling damage is not at the injection well wall, but it gradually moves to deep reservoir as injection time increases, while the damage degree gradually increases. The damage degree of injection well wall does not increase with increase in injection time, but remains constant. The magnitude and scope of the cooling damage gradually increases and its fluctuation characteristics clearly increases.

Study on the Temperature Distribution of High Pour Point Oil by Integrated Method Based on Well Log, Geological Data and Experiment

High pour point oil reservoir contains various typical properties; such as a kind of high freezing point, high paraffin content and high cloud point temperature reservoir, while the temperature is regarded as high sensitive parameter for oil reservoirs. The current research aim is to develop and assess the effect by cold water flooding, the structure and properties model was built with the combination method of reservoir geological modeling and simulation. Various degrees of cold damage have deep relation with paraffin deposition and reservoir channel plug due to decline of temperature below the cloud point temperature. Precipitated paraffin has changed the rheological properties of crude oil, which can increase filtration resistance and reducing the oil displacement efficiency. Furthermore, model simulation analysis results compared under two different conditions cold and hot water flooding and predicted the inter well temperature field distribution belongs to reservoir through the model numerical simulation. Present study depicts that the integrated method base on log, geological data and experiment can predict and analysis the temperature variation efficiently, while thermal displacement method has efficiently improved the high pour-point oil reservoir development effect, increasing oil mobility and enhancing oil recovery.

The Performance of a High Paraffin Reservoir Under Non-isothermal Waterflooding

This study analyzes the performance of a high paraffin reservoir under cold waterflooding for 17 years using a 3-D finite difference simulator and analytical solution of injection wellbore temperature profile to upgrade reservoir management strategies. The reservoir has been marked by injectivity issues, early injection rate decline by half initial values and low incremental recovery, hence subject to alternate developmental schemes. The influence of cold waterflooding is assessed from simulated temperature maps due to nonisothermal injection and solution of injection well temperature profile.

SIMULTANEOUS HEAT AND FLUID FLOW IN POROUS MEDIA: CASE STUDY: STEAM INJECTION FOR TERTIARY OIL RECOVERY

Heat transfer and fluid flow in porous media occur simultaneously in thermal enhanced oil recovery and significantly increase the rate of energy transfer. The purpose of this investigation was to take advantage of such contemporary transfers and to study heavy oil recovery efficiency using hot-water flooding, cold-water flooding, and steam injection into porous media. A set of multistage laboratory tests was performed to find the temperature profile during steam injection as a means of tertiary oil recovery. Sand-packed models were utilized to investigate the oil recovery efficiency during cold and hot water injection as well as steam flooding for both secondary and tertiary oil production stages. An oil bank was formed in steam injection during the tertiary oil recovery from a vertical standing sand-packed model, resulting in very high oil recovery efficiency. Steam injection was found to be very effective, compared to cold- and hot-water flooding, for the recovery of heavy oil. Based on the principles of transport phenomena in porous media, a mathematical model was developed to predict the temperature profile during the steam injection process. Satisfactory agreement is achieved between the temperature profile predicted from the model and the experimental results.

Results of a Steamdrive Pilot Project in the Ruehlertwist Field, Federal Republic of Germany

Summary Production from the area of the Ruehlertwist field close to the northern aquifer is governed by pressure maintenance by water influx, sustained by reinjection of produced water downdip of the oil/water contact (OWC) in the north of the structure. Because of the high in-situ viscosity (175 mPa·s [0.175 cp]) of the 0.9-g/cm3 [25°API] crude in this area, only 22% of the stock-tank oil initially in place (STOIIP) has been recovered. Therefore, it was decided by the consortium operating the field (BEB, Deilmann A.G., Preussag A.G., and Wintershall A.G. as operator) to perform a pilot test to investigate the feasibility of steam injection under waterdrive conditions in this highly watered-out part of the field. In Dec. 1978 steam injection into Well Rt 208 was started. The second well, Rt 56, began steam injection in April 1979. The 580 000-m2 [143-acre] pilot area contained 2.655×106 m3]17×106 bbl] STOIIP. By the end of Feb. 1983 about 1 080 000 m3 [138,139,840 cu ft] steam (32.8% PV) have been injected into the reservoir. During these 4 years the additional recovery attributable to steamflooding accumulated to up to 6.8% STOIIP. This paper describes the reservoir, the necessary facilities, and the pilot project performance. Conclusions drawn from the pilot performance will be considered for future production strategy. Introduction The Ruehle structure, which comprises the Ruehlertwist and Ruehlermoor oil fields, is located in the Emsland area of the Federal Republic of Germany near the Dutch border (Fig. 1). It is an east-west-trending anticline of the Lower Cretaceous Age. The oil-bearing area of the structure is roughly 27 km2 [10 sq miles] of which one quarter belongs to the Ruehlertwist oil field. This field was discovered in 1943 and has been developed since 1948–49. A total of 138 wells with a spacing of approximately 200 m [656 ft] were drilled by the end of 1957. The main oil reservoir consists of the Bentheim sandstone (Valanginian), an unconsolidated sandstone at an average depth of 800 m [2,625 ft]. The Bentheim sandstone consists of four layers:Flaser Sandstone (approximately 8 to 10 m [26 to 33 ft] gross thickness),Upper Sandstone (approximately 8 to 22 m [26 to 72 ft] gross thickness),Clay (approximately 2 to 4 m [7 to 13 ft] gross thickness), andLower Sandstone (approximately 6 to 8 m [20 to 26 ft] gross thickness). The main producing zone in the Ruehlertwist oil field is the Upper Sandstone. It is a well-sorted sand of medium-size quartz grains and a low clay content in the upper part of the zone. The lower part of the Upper Sandstone is also well sorted, containing a very fine-grain sand with low clay content. The clay content of the zone gradually decreases from base to top and, hence, permeability increases. The range of permeability for air is on the order of 300 to 10,000 md. Typical core and log data of Wells Rt 25A and Rt 187 are shown in Figs. 2 and 3. Three drive mechanisms are used in the Ruehlertwist oil field (Fig. 4).In the northern and southwestern areas, primary production is obtained by edgewater drive.In the top structure area, solution gas drive and fluid expansion are the primary production mechanisms.The southeast area has increasing clay content and decreasing permeability to the southeast and an east-west-trending fault. This part of the field is sealed from the edgewater drive and driving energy comes from solution gas and expansion only. The depth of the Upper Sand is 700 m [2,297 ft] at the crest of the anticline, 870 m [2,854 ft] on the north flank at the oil/water contact, and 800 m [2,625 ft] on the south flank. The dip of the producing formation ranges from 0 to 9°, being less in the northern part of the field. Until the 1960's, the top area and the southeast part of the Ruehlertwist field were produced by fluid expansion and solution gas drive. To improve the low primary recovery factor, which resulted from the high in-situ oil viscosity of the 0.9-g/cm3 [25°API] crude, water injection was started in the southeastern part in 1961 and in the top area of the field in 1968. The recovery resulting from primary and secondary energy (repressuring of the depleted reservoir by natural water influx and cold water flooding) was low because of the unfavorable mobility ratio and the type of reservoir (complex petrophysical characteristics including structural barriers created from major east-west faulting, which separates the reservoir into sections more or less affected by the edgewater drive).

Two-Dimensional Method For Predicting Hot Waterflood Recovery Behavior

Abstract The purpose of this paper is to further the understanding of reservoir response to hot-water injection by describing a two-dimensional, mathematical model of the process. Key assumptions are that no gas phase is present, and that the injected fluid reaches thermal equilibrium instantaneously with the reservoir fluids and sand. The resulting system of three partial differential equations is solved simultaneously through the use of a "leap-frog" application of standard alternating direction implicit methods for the solution of the mass-balance equations and the method of characteristics for solution of the energy-balance equation. The utility of the mathematical model is demonstrated by comparing numerical and analytic temperature distributions for hot-water bank injection and by comparing calculated with observed field behavior. Additional calculations show that hot waterflooding can recover significantly more oil than cold waterflooding, and that a hot-water bank recovers, with less energy input, nearly as much oil as continuous injection. Introduction Consistent field success with hot fluid injection processes requires good reservoir description and a thorough understanding of recovery mechanisms. The latter is fostered by a combination of well designed experimental studies and physically sound mathematical modeling. The purpose of this paper is to further the understanding of reservoir response to hot-water injection by describing a two- dimensional mathematical technique, indicating its validity, and demonstrating its utility for studying the effects of reservoir and operating parameters. Published experimental studies of hot fluid injection processes are few. Even if extensive data were available two considerations discourage exclusive reliance on laboratory or field work. First, because of the severity of scaling requirements, laboratory results must be interpreted with care. Second, because of the one-shot nature of field experiments - injectivity/productivity tests and pilot floods - results seldom are available over the desired range of operating conditions. These factors emphasize the need for devoting attention to mathematical modeling to complement laboratory and field work. Through the use of mathematical models, scaling uncertainties can be bridged and response can be predicted for unique combinations of reservoir and operating conditions. Numerous mathematical models developed during recent years enable us to calculate temperature distributions, thermal efficiency (or conversely, fraction of heat lost), and oil recovery behavior for hot fluid injection. Ramey and Spillette recently have provided reviews of these methods. Most models have concentrated on predicting temperature distributions and thermal efficiency; few have been directed at predicting oil recovery. Although these techniques are useful for estimating effects of reservoir parameters and operating conditions on process performance, results are limited by the assumptions made and by the methods of coupling independently solved fluid-flow and energy-balance equations. A computer-based method is presented for predicting total reservoir response to hot-water injection that obviates most simplifying assumptions. The model simulates fluid flow and heat transfer in two dimensions within a vertical cross-section spanning the oil sand and adjacent unproductive strata. Known numerical procedures are used to solve the governing partial differential equations. The mathematical model handles the effects of reservoir heterogeneity, gravity, capillarity, relative permeability and temperature-dependent fluid properties. In addition, a wide range of operating conditions can be modeled, including hot-water followed by cold-water injection. Mathematical Description of Hot-Water Injection Key assumptions in the mathematical model for hot- water injection are thatno gas phase is present andthe injected fluid reaches thermal equilibrium instantaneously with the reservoir fluids and sand. Relative permeability and capillary pressure are assumed independent of temperature. JPT P. 627ˆ