Heavy Oil Waterflooding Research Articles

Technology Focus: Heavy Oil (April 2023)

_ Heavy oils are characterized by high-density, high-viscosity, and high-heavy-fraction components. One of the more common characteristics of heavy oil reservoirs is a low primary recovery factor, which is mainly because of unfavorable mobility ratios between oil and water, negligible solution drives, and faster decline of reservoir pressures because of relatively low oil compressibility. Most of the technologies that apply to heavy oil reservoirs need to address the mobility ratio or viscous forces before any flooding. Given the complex nature of heavy oil reservoirs, paper SPE 209328 present a comprehensive review of the latest technologies and work flows developed for heavy oil reservoir management. Although secondary oil production methods such as waterflooding, water-alternating-gas injection, and gas drive might not be efficient in recovery from heavy oil reservoirs, the applicability and success of these methods can be analyzed on a reservoir basis. The offtake and throughput management philosophy for heavy oil waterflooding is not the same as for classical light oil, and it could play a major role in recovery efficiency. The key point is to understand the nature of heavy oil and reservoir heterogeneity regarding their fluid and rock properties. Recent technology advances in hardware and software have enabled the industry with tools that allow achieving full-field high-resolution simulation modeling; therefore, performing a realistic reservoir simulation is achievable. This might decrease the loss of millions of dollars before field applications. Paper SPE 210185 presents an example of taking advantage of recent simulation technologies and presents a method and work flow under subsurface uncertainty for a large heavy oil field with complex geological characteristics, a long production history, and many wells. The work-flow design is applicable for other fields with similar characteristics and delivery objectives. Paper SPE 203783 discusses the results of a recovery-optimization study conducted in a heavy oil field in south Oman aimed at improving the understanding of deep bottom-up water injection. Recommended additional reading SPE 205449 First Successful Controlled Dumpflood in Deepwater Gulf of Mexico Results in Promising Incremental Rate and Recovery by Bilal A. Hakim, Talos Energy, et al. URTeC 2021-5077 Heavy Oil Polymer Enhanced Oil Recovery in the Challenging Alaskan Arctic—It Works! by A. Dandekar, University of Alaska Fairbanks, et al. SPE 212387 Evaluation of the Oil Recovery and Economic Benefit of the First-Ever Polymer flood Field Pilot To Enhance the Recovery of Heavy Oils on Alaska’s North Slope Using Machine-Assisted Reservoir Simulation by Cody Douglas Keith, University of Alaska Fairbanks

Study of cyclic waterflooding for improving oil recovery in Lukeqin heavy oil reservoir

Long term water injection in Lukeqin heavy oil field results in a rapid increase of water cut. It is an urgent need to conduct a study on the influencing factors of heavy oil waterflooding. Experiments are used to conduct the effect of heavy oil viscosity change law on the development. Numerical simulation is used to analyze the viscosity and rhythmic conditions to clarify the production mechanism of waterflooding in heavy oil reservoirs. The feasibility study of cyclic water injection in heavy oil reservoirs is analyzed because water channeling is serious in continuous water injection, while cyclic waterflooding can slow down the injection water surge. To begin with, when using the improved cyclic waterflooding method, the working mode, reasonable number of cycles and the timing of cyclic waterflooding need to be optimized to obtain the optimal combination injection scheme. Furthermore, to investigate the mechanism of oil increase by cyclic waterfiooding, different production wells were divided into the channeling well, the seepage channel well and the normal wells according to the streamline strength, and then analyzed the mechanism influencing factor such as pressure difference and capillary force to study when cyclic waterflooding for the three types of production wells. Pressure differential are the most effective in increasing oil in the normal well, followed by the seepage channel well, and channeling well. The capillary force have the best water control effect on the channeling well, followed by the seepage channel well and the normal well. The capillary force play a dominant role in the well water control in the channeling well. The effect of increasing oil in the normal well is dominated by pressure difference. Well pressure difference and the capillary force have little to no dominant effect on the seepage channel well. The results demonstrate that cyclic waterflooding can effectively improve the recovery rate of three types of wells, with the degree of improvement from good to bad, in the order of the normal well, the channeling well and the seepage channel well. The novelty of this work lies in the combination of experimental and numerical models (mechanistic and practical) and simulation studies using three different types of wells, thus analyzing the mechanistic influence of pressure differential and capillary forces in it and concluding the dominant mechanism of action - the mechanism of development of heavy oil cyclic waterflooding is the effect of pressure difference control on production increase and capillary force control on reducing water cut.

Waterflooding of Heavy Oil Reservoirs

Waterflooding or polymer flooding is sometimes dismissed as an ineffective process for heavy oil fields, with development plans focused on more exotic and expensive recovery mechanisms such as chemical or thermal processes. There are a number of unique mechanisms that operate in heavy oil fields under water and polymer flood. It is, therefore, possible to succesfully flood heavy oil reservoirs with viscosities up to and beyond 10,000 cp oil viscosity. This work elaborates on the unique mechanisms operating in heavy oil water and polymer floods, presents a workflow for successfull implementation and supports its conclusions with a number of case studies, namely, actual successful field examples from Canadian heavy oil fields. The hope is that, this experience can be translated to heavy oil fields in other parts of the world including Turkey.

W/O emulsions generated by heavy oil in porous medium and its effect on re-emulsification

Water/hot water flooding and steam stimulation are usually used for heavy oil recovery. However, W/O emulsions are generated when heavy oil and water flow in porous medium of formations, which can seriously restrict the recovery effect in the middle or late stage. First, the influence of the W/O emulsion on efficient heavy oil recovery is analyzed by the production dynamics and produced fluid emulsified states of oilfields. Then, the W/O emulsion generation process during heavy oil entrapment and water flooding recovery was simulated. The effects of permeability, porous medium shearing distance and heavy oil viscosity on the emulsified state of W/O emulsions were studied. The properties of W/O emulsions were tested. Before reaching the final emulsified state, the lower the permeability and the longer the porous medium shearing distance, the more fully emulsified of the W/O emulsion. In the final emulsified state, the droplet sizes of the W/O emulsions generated by different viscosities of heavy oil are basically the same at the same water content. As the water content increases, the W/O emulsion droplet size grows first, then tends to stabilize, and finally stabilizes at between 2 and 3 μm. The viscosity of the W/O emulsion increases as water content increases and its viscosity increases significantly at high water contents. The lower the viscosity of dehydrated heavy oil is, the greater the increase of the viscosity of W/O emulsion increase. The viscosity of 70% the water content W/O emulsion is more than 15 times that of the dehydrated heavy oil. Finally, the effects of the water content, surfactant concentration, oil–water ratio on the emulsified state, droplet size distribution and its fluidity in porous medium were studied by simulating the re-emulsification process of W/O emulsion and surfactant solution. A W/O/W emulsion would formed by re-emulsification of the W/O emulsion and surfactant solution. As the water content of W/O emulsion increases, the droplet size of the W/O/W emulsion formed by re-emulsification increases, and its fluidity in porous medium decreases. The average emulsion droplet size (50% water content) after re-emulsification is 6.29 times that of emulsions formed by dehydrated heavy oil, and the apparent viscosity in porous medium is 15.05 higher. This study provides significant information for understanding the key issues in the efficient development of heavy oil reservoirs throughout their life time and the research and development of high-efficiency emulsion flooding systems.

Nuclear Magnetic Resonance (NMR) mapping of remaining oil distribution during sequential rate waterflooding processes for improving oil recovery

At the conclusion of waterflooding phase, significant volume of oil still remains in reservoir formations. In this paper, waterflooding was performed at a designed sequential rate mode with an aim to further reduce the remaining oil saturation (Sor). Waterflooding process was monitored continuously by a low-field Nuclear Magnetic Resonance (NMR) spectrometer attempting to map pore-scale displacing behaviors and also quantify the reduction in Sorin-situ. The results showed that the main pore size of the cores ranged from 1.6 μm to 63.0 μm inferred by T2 (transverse relaxation time) distributions. The value of Sor in the cores increased towards the outlet face during waterflooding because of capillary end effect, which became more significant for heavy oil. At the termination of this waterflooding process, Sor was found to be further reduced by approximately 5.0% in the presence of thief water pathways as a result of the improved viscous forces. Water fingering and capillary imbibition effects were clearly visualized in the NMR images. These observations are expected to be useful for heavy oil waterflooding operations especially in post-breakthrough phase.

Experimental study on pressure control strategies for improving waterflooding potentials in a heavy oil-methane system

Due to the adverse mobility ratio conditions in heavy oil waterflooding processes, the viscous force is not as significant as that in conventional waterflooding in terms of enhancing oil recovery. Instead, pressure related mechanisms, such as foamy oil flow and solution gas drive, might have significant effects on waterflooding performances when an operating strategy is beneficial (e.g. voidage replacement ratio less than one).In this study, a series of waterflooding tests are performed to study the beneficial operating strategies in a heavy oil-methane system from the pressure control aspect. The pressure control strategies include primary-ended waterflooding (Strategy 1), primary-plus waterflooding (Strategy 2), pseudo-continuous injection with cyclic production (Strategy 3), and cyclic injection with cyclic production (Strategy 4). The depletion rates include 0.45kPa/min, 1kPa/min, 2kPa/min, and 3kPa/min.Experimental results show that the optimal pressure control strategy for the heavy oil-methane system is Strategy 2. The ultimate oil recovery and overall average production rate are inversely changed with the depletion rate increasing in Strategy 2. To get a balance between the ultimate oil recovery and overall average production rate, the optimal depletion rate, 2kPa/min, is obtained. By comparing the performances of Strategy 2 under different depletion rates, the relationship of voidage displacement ratio (VRR) with the depletion rate as well as the optimal VRR for waterflooding are obtained. Moreover, it is found that, with depletion rate increasing, positive effects of depletion rate decrease at foamy oil flow stage and increase at solution gas drive stage.

Correlations of viscous fingering in heavy oil waterflooding

In order to include viscous instability in modeling heavy oil waterflooding, it is essential to predict the nature of viscous instability. It is still unclear as to whether previous findings of viscous fingering in immiscible displacements in the presence of high single-phase permeabilities and linear displacement schemes are valid in displacement schemes similar to oil-field patterns (e.g., five-spot) and what the effect of dispersion (caused by varying velocity profiles) is on viscous fingering. To overcome the limitations of previous studies of viscous fingering in immiscible displacements, we conduct experiments in low-permeability, one-quarter five-spot patterns. The correlation of experimentally measured oil recoveries, pressure drops, saturation profiles, viscous fingers length and width, dynamic population of fingers, and rate of growth of fingers population with time and front position are discussed. Study of viscous fingering patterns in heavy oil waterflooding conducted in this work provides new insights into the onset of fingering and fingers development.

Interwell connectivity evaluation in cases of changing skin and frequent production interruptions

Evaluating interwell connectivities can provide important information for reservoir management by identifying flow conduits, barriers, and injection imbalances. Injection and production rates, in ideal conditions, contain connectivity information. A number of methods have been proposed to predict connectivity based on these data. Unfortunately, many of these rate based methods have not proven to be as successful as intended because of factors external to the reservoir. Field maintenance procedures, such as shut-ins and work-overs, cause production rate changes which are not caused by injection rate fluctuations but which mislead connectivity estimators. We have developed a method which is tolerant to changes caused by external factors. This method, called the Multiwell Compensated Capacitance Model (MCCM), is based on the superposition principle. It can analyze injection and production data when producers׳ skin factors change, new producers are added, or active producers are shut-in. The MCCM also deals with another common problem in field data, which is when there are frequent producer shut-ins within sampling intervals (mini-shut-ins). For example, a producer is shut-in for a few days when flow rates are measured every month. By deriving the MCCM equations using average rates, we have developed an efficient approach to overcome this problem. In several synthetic cases with varying skin, long term shut-ins, and frequent mini-shut-ins, the MCCM successfully determined the true connectivity parameters and predicted the production rates accurately. For a set of field data from a heavy oil waterflood in Saskatchewan, we could improve the R2 of the predicted rates by 20–35% compared to another method and observed good agreement with geological information. In general, we may not find a long enough time interval of injection and production data where the producers׳ conditions stay constant. Applying earlier methods in such cases may give misleading connectivity results and inaccurate rate predictions. Adopting the approaches described in this paper helps geoscientists and engineers to have a better understanding of reservoir heterogeneity and its effects on fluid flow in the reservoir.

Performance Prediction of Waterflooding in Western Canadian Heavy Oil Reservoirs Using Artificial Neural Network

This study presents a successful application of multivariate partial least-squares (PLS), response surface methodology (RSM), and artificial neural network (ANN) to develop a new diagnostic tool for performance prediction of waterflooding in heavy oil reservoirs. The data used in this study consist of 120 operational and reservoir parameters for 177 waterfloods in heavy and medium oil reservoirs in western Canada (i.e., Alberta and Saskatchewan). This study also used 15 numerically devised indices for performance evaluation of water injection, based on collected injection and production histories of studied waterfloods. To reduce the number and complexity of input parameters of ANN models, a comprehensive PLS analysis was conducted. In addition to parameter selection, the PLS model provided a more in-depth understanding of differences between heavy and medium oil waterfloods. Next, RSM was used to improve the quality of the database for a selected combination of 38 reservoir and operational parameters by predicting some of the missing data. Finally, ANN models were developed using the feed-forward backpropagation algorithm with momentum for error minimization. The developed models show the superior ability of the ANN for creation of an efficient reservoir engineering tool for fast performance prediction of waterfloods using easily obtainable operational and reservoir parameters. The developed models in this study can be incorporated into reservoir engineering, risk assessment, and production optimization software programs to improve the quality of predictions based on more than 50 years of waterflooding experience in western Canada.

Mechanisms of Heavy Oil Recovery by Low Rate Waterflooding

Abstract At the conclusion of primary heavy oil production, significant volumes of oil still remain in the reservoir under depleted reservoir pressure. Waterfloods are often considered for additional oil recovery. It is accepted that conventional oil waterflooding theory is not applicable for heavy oil. However, there is a lack of understanding of how waterfloods should perform in these reservoirs, particularly after water breakthrough. In this study, waterfloods were performed at multiple rates in cores containing heavy oil and connate water. In some cores, oil was initially free of solution gas, and waterfloods were a primary recovery process. In other cores, waterfloods were performed after primary production. Experiments were performed in linear systems for a high-viscosity oil (11,500 mPa·s at 23°C), at different injection rates. The influence of viscous and capillary forces is studied in primary vs. secondary recovery systems. A common misconception is that capillary forces are negligible in heavy oil; however, this work shows that these forces are significant, and that water imbibition after water breakthrough can lead to improved oil recovery in both primary and secondary waterfloods. Introduction The Canadian deposits of heavy oil and bitumen are some of the largest in the world. Recent estimates by the Alberta Energy and Utilities Board(1) suggest that this resource could exceed 270 billion m³ in Alberta alone, with a significant portion of this oil located in reservoirs where energy-intensive thermal operations will not be economic. Heavy oil is a special class of this unconventional oil, which has viscosity ranging from 50 - 50,000 mPa·s (cp) and low API gravity. Heavy oil reservoirs are often high-porosity, high-permeability, unconsolidated sand deposits. Permeability of the sand averages in the range of 3D, but oil does not flow easily because of its high viscosity(2). The oil may contain dissolved solution gas at initial conditions; thus, a fraction of the oil can be recovered through solution gas drive. Primary production can recover around 5% of the oil in place(1), leaving significant oil volumes in the reservoir for potential secondary recovery. Waterflooding is a common technique for secondary oil recovery in conventional oil reservoirs. In heavy oil systems, the extremely high oil viscosities lead to adverse mobility ratio conditions; thus, water will tend to "finger?? through the oil, and recoveries are expected to be extremely low(3,4). Despite the poor recoveries predicted theoretically, there have been numerous reports of heavy oil waterfloods performed in the literature(5-8). All of these studies report poor sweep efficiencies and low overall recovery. However, it is significant that in all cases some oil was still recovered, despite the highly adverse mobility ratios in the waterfloods.

Technology Focus: Heavy Oil (March 2009)

Technology Focus In January 2008, the price of benchmark 13°API Midway Sunset crude was approximately USD 85/bbl, whereas in January 2009, it was approximately USD 30/bbl. As the price of oil increased during the past few years, many people commented on how the high price was good for studying and, eventually, recovering unconventional resources such as heavy oil. With the current lower-price environment, I have heard the opposite. Additionally, many individuals declared themselves to be experts in areas of unconventional-resource recovery when prices were high, and there seems to be less enthusiasm for this field now. This perceived reversal of fortune reminds me of a short story that my children enjoy reading. In the book Zen Shorts by Jon J. Muth, a family of three children is told Zen-inspired short stories to help them understand and cope with everyday events. In one short story, a farmer, who coincidently is a rabbit, experiences a series of fortunate and unfortunate events. His friends and relations offer congratulations and sympathy on his good or bad luck, as appropriate. To comments such as "Such good (or bad) luck," the farmer always replies "maybe" and carries on with his work. Although oversimplified here, the story teaches that good and bad luck happen together, and in life you need to cope with both because you never know what will happen next. If this story were retold for the oil industry, industry observers and commentators might play the role of friends and relations. The wise farmer is the petroleum engineer(s) who knows that the promise of heavy oil and other unconventional resources has a spectrum of recovery techniques under development, and who works toward economical recovery. He/she resists price exuberance and prepares for inevitable changes in fortune. The price of oil represents luck that can never quite be predicted. Unconventional resources are as important a component in meeting future energy demand this year as they were last year. In this month's synopses and reading list, you will find articles that span many aspects related to heavy hydrocarbons. Downhole electrical heaters remains an exciting area for providing precise, targeted heating. Microwaves also provide the ability to heat the formation selectively and, possibly, induce in-situ upgrading. Likewise, in-situ combustion is more difficult to engineer compared to steam injection, but it is more widely applicable, is potentially more energy efficient, and provides mild upgrading of heavy hydrocarbons. Here, we see its application in fractured systems. Other articles could be classified as minimization of carbon footprint through capture and reinjection of carbon dioxide and as implementation of cold-recovery methods. Heavy Oil additional reading available at the SPE eLibrary: www.spe.org IPTC 12536 • "Microwave-Assisted Gravity Drainage of Heavy Oils" by Berna Hascakir, Middle East Technical University, et al. SPE 117327 • "Increasing Oil Recovery from Heavy-Oil Waterfloods" by Bradley W. Brice, SPE, BP, et al. SPE 118226 • "Experimental and Numerical Comparison of Flooding Schemes To Enhance Recovery of Light-/Medium-Heavy Oil in an Offshore Oil Field" by Bin Yang, China University of Petroleum, et al. SPE 115201 • "Achieving Long-Term Zonal Isolation in Heavy-Oil Steam-Injection Wells: A Case History" by David Kulakofsky, Halliburton, et al.

Heavy Oil Waterflooding: Effects of Flow Rate and Oil Viscosity

Abstract Many countries in the world contain significant heavy oil deposits. In reservoirs with viscosity over several hundred mPa's, waterflooding is not expected to be successful due to the extremely high oil viscosity. However, in many smaller, thinner reservoirs, or reservoirs at the conclusion of cold production, thermal enhanced oil recovery methods will not be economic. Waterfloods are relatively inexpensive and easy to control; therefore, they will still often be employed in high viscosity heavy oil fields. This paper presents experimental findings of waterflooding in laboratory sandpacks for two high viscosity heavy oils of 4,650 mPa.s and 11,500 mPa.s at varying water injection rates. The results of this work show that capillary forces, which are often neglected due to the high oil viscosity, are important even in heavy oil systems. At low injection rates, water imbibition can be used to stabilize the waterflood and improve oil recovery. Waterflooding can therefore be a viable non-thermal enhanced oil recovery technology, even in fields with very high oil viscosity. Introduction Although conventional oil reserves are declining in many countries, the global energy demand is still increasing. As a result, the industry focus is now shifting towards unconventional oil resources, such as the oil sands in countries like Canada and Venezuela. The size of this resource base is immense, but the production of high viscosity crude oil carries its own unique challenges. Heavy oil is a special class of this unconventional oil, and has viscosities ranging from 50 to 50,000 mPa.s. Heavy oil reservoirs are often found in highly porous, highly permeable, unconsolidated sand deposits. At reservoir conditions, the oil may contain dissolved solution gas; thus, some oil can be initially recovered using the energy from heavy oil solution gas drive. At the end of primary production, however, a significant amount of oil still exists for potential secondary recovery. Many of these reservoirs are small and thin or were disturbed during primary production, making them poor candidates for expensive thermal enhanced oil recovery strategies. In times of uncertain commodity pricing, it is beneficial to examine the potential for relatively inexpensive, non-thermal oil recovery techniques. Waterflooding is often employed, at least initially, in heavy oil reservoirs, both along with or after primary recovery in order to re-pressurize the reservoir and displace oil to producing wells. In these applications, it is very important to understand the forces that are present in the reservoir and how they can be used to properly design the waterflood. Specifically, proper design and maintenance of waterfloods requires comprehension of how viscous oil can be displaced by water, and how oil recovery can be optimized. This work presents the results for water injection into laboratory sandpacks containing gas-free heavy oil of varying viscosity. The responses for different waterfloods are compared in order to investigate the mechanisms by which heavy oil can be recovered by water injection. Theory Waterflooding of oil reservoirs is a well-recognized technique for oil recovery after primary production. In conventional oil, waterflooding theory has been well documented(1).

Role of Operating Practices on Performance of Waterfloods in Heavy Oil Reservoirs

Abstract Identification of operating conditions that have been beneficial or injurious to overall performance of past waterfloods in heavy oil reservoirs is the first essential step towards optimization of similar projects in the future. Comparative analyses of performance of various waterfloods in a given region (deposited under similar conditions) can be very instructive to identify such conditions. Insights on performance of waterfloods in heavy oil reservoirs were derived from a comparative evaluation of recent performance history of three selected waterfloods. These waterfloods involved increasing, decreasing and steady water injection rates. It was seen that aggressive injection rates lead to increased oil rates, but at rapidly increasing water cuts. Decreasing water injection rates, on the other hand, lead to low oil rates, but with water cuts increasing relatively more gradually. There is, therefore, an economically optimal water injection rate strategy for each specific situation. Introduction In the current environment of volatile oil prices and economic uncertainties, there is a heightened need for reviewing the cost-effectiveness of ongoing waterflood and improved oil recovery (IOR) operations within the constraints of low incremental costs and risks. Some of the options being pursued include enhanced surveillance, benchmarking of performance against other successful projects in analogous reservoirs, intense characterization and simulation, upgrades to facilities, improvement in injection water quality and selective placement of additional injectors and producers. In viscous fingering-dominated waterfloods, aggressive water injection aggravates water channelling. High injection rates (sub-fracture) lead to high initial oil rates in the short-term, but they subsequently give rise to excessive water channelling which may result in loss of cost-effectiveness of the waterflood and, in some cases, premature abandonment. On the other hand, low injection-production rates (processing rates) in heavy oil waterfloods lead to relatively low oil rates, long payout periods and a long project life. There is, therefore, an optimal processing rate/strategy for each specific situation (based on technical and economic considerations) and, clearly, there is a need for systematically identifying it. Since the 1980s, over 70 waterfloods have been operated in the medium and heavy oil reservoirs of Alberta and Saskatchewan in Western Canada. Waterflooding in these reservoirs involves adverse mobility ratio and viscous fingering/water channelling leading to relatively early water breakthrough. Resulting requirements for handling large amounts of water poses formidable problems. This study was undertaken to explore whether a judicious scheduling of injection and production rates could improve cost-effectiveness of similar operations in the short- and long-term. We examined performance histories of several ongoing waterfloods, and three selected waterfloods are reviewed here. We did not have access to many details on these projects. We believe there is a persuasive case for our hypothesis. It is understood that the field data examined were, by no means, 'controlled' (i.e. there may possibly exist factors other than the ones we focused on in this review, and all cases may not strictly be comparable). Methodology We compared the performance of three selected waterfloods in the heavy oil reservoirs of Southern Alberta; namely, Jenner Upper Mannville O, Jenner Upper Mannville JJJ and Retlaw Mannville D8D.

Processes Responsible for Heavy-Oil Recovery by Alkali/Surfactant Flooding

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 113993, "Investigation into the Processes Responsible for Heavy-Oil Recovery by Alkali/Surfactant Flooding," by J. Bryan, SPE, University of Calgary and TIPM Laboratory; A. Mai, SPE, University of Calgary and TIPM Laboratory and Laricina Energy; A. Kantzas, SPE, University of Calgary and TIPM Laboratory, prepared for the 2008 SPE Improved Oil Recovery Symposium, Tulsa, Oklahoma, 19-23 April. The paper has not been peer reviewed. This paper describes a suite of alkali/surfactant (AS) floods that were performed in systems containing viscous heavy oil (11 500 mPa⋅s). The study investigates how AS injection can be used to generate oil-in-water (OIW) emulsions, which can in turn improve sweep efficiencies and oil recovery. Data were obtained from coreflooding, with in-situ saturation measurements made using low-field nuclear-magnetic-resonance (NMR) analysis. The corefloods in this study indicate that emulsification is most efficient when used to block preformed water channels and improve the sweep efficiency of the flood. Introduction Several countries, including Canada and Venezuela, contain significant deposits of heavy oil and bitumen. These oil-sands are high-porosity and -permeability unconsolidated reservoirs. The viscosity of the oil in place may range from tens to millions of mPa·s at reservoir conditions, and the oil densities approach or are higher than that of water. Recent estimates put the primary recovery of heavy oil at an average of approximately 5% of the original oil in place (OOIP), with significant oil resources remaining as potential for secondary and tertiary recovery. However, many of the reservoirs in Canada are relatively small or thin, and were possibly disturbed during primary production. As a result, these reservoirs are not prime candidates for expensive thermal or hydrocarbon-solvent enhanced-oil-recovery technologies. Therefore, less-expensive (nonthermal) methods of recovering the oil must be considered. Previous research focused on improved heavy-oil recovery by application of waterflooding and AS flooding. This work found that during a heavy-oil waterflood, water will break through very early in the life of the flood because of viscous instabilities, resulting from the adverse water/oil mobility ratio. After water breakthrough, continuous channels of water existed throughout the reservoir. At later stages in a heavy-oil waterflood, capillary forces and water imbibition were the dominant recovery mechanism. At low injection rates, significant volumes of heavy oil can be recovered after water breakthrough, though at a high water cut. AS injection could be considered either as a primary- or secondary-recovery process. Overall, a combination of waterflooding and AS flooding can lead to significantly improved oil recovery beyond that of primary production. Pressure and recovery data were analyzed to infer how the chemical flood worked, and NMR spectra of the fluids in the sand pack were monitored to understand the wettability of the core as the flood progresses.

Interference Testing to Characterize the Injection Behaviour of a 20-Acre Pattern in the Court Field

Abstract In the Court Field, the middle Bakken Sand Pool has been operated as a heavy oil waterflood for over 15 years. However, unrecovered oil volumes in the pool remain attractive for improved recovery schemes. Recently, the Court Middle Bakken Reservoir model was updated to evaluate the potential for downspacing and waterflood optimization of the reservoir. The potential for 20-acre downspacing for both infill drilling and additional water injection was identified by this study. As part of the additional development program, an injector producer well pair was drilled to create a new injection pattern with reduced inter-well spacing. Reservoir pressures, water saturation and effective permeability to water in the pattern were determined by RFT and log data. Pattern characterization was complemented by an interference test, including all the wells in the pattern. Analytical and numerical tools were used in the test design. The most comprehensive results were obtained by local grid refinement of the pattern area in the full field simulation model. Unavoidable interference with a neighboring pattern during the test was predicted. In order to account for this effect, it was decided to run the test with the new injector active intermittently. The complete test design and analysis of the results are described. In addition, a comparison of pressure measurements by downhole gauge and acoustic well sounder are presented. Introduction The Court Field, located in west central Saskatchewan, produces 17 ºAPI heavy crude from the Middle Bakken Formation, using vertical wells and a waterflood recovery scheme. The Court Bakken Sand was discovered in November 1981. The Court Bakken Sand Voluntary Unit No. 1 was formed in 1988 and waterflood commenced with only 2% of OOIP produced. There are 39 producing oil wells and 21 water injection wells currently in operation within the main pool. The current recovery factor is approximately 20%, with some wells producing up to 30m3/d oil. Recently, Majcher et al.(1) presented a geological and engineering overview of the reservoir. The Middle Bakken Formation was deposited as NE-SW trending sand ridges. The pool has undergone significant collapse of the Torquay Formation with the subsequent creation of extensive post-depositional sinkholes within the Bakken. This structural deformation interrupts the lateral continuity of the sand ridge and its characterization is the most challenging to further field development and effective waterflood management. Another important Bakken heterogeneity is the change in well log signature that represents the variation in facies at the ridge edges(2). This facies distribution within the Middle Bakken correlates with the waterflood response. Majcher et al.(1) identified the potential for infill drilling of producers and injectors near the edges of the pool. An injector-producer pair was recently drilled in Section 36-033-28W3M on 20-acre spacing. An interference test with four wells was conducted to investigate how the heterogeneities described above affect the waterflood performance of the newly configured pattern.

Improving the State of the Art of Western Canadian Heavy Oil Waterflood Technology

Abstract Heavy oil waterfloods have been operated in Saskatchewan and Alberta for up to 50 years, yet remarkably little discussion of the theory or operation of heavy oil waterflooding has been published. Conventional waterflood theory is based on assumptions that are not encountered in heavy oil reservoirs, and those theoretical and operational experiences should not be substituted. This editorial draws upon information from the relatively small number of significant theoretical and field discussions of Western Canadian heavy oil waterflooding available in the public domain to establish that the "state of the art," including proposed production mechanisms, prediction of performance, and improvement of performance, is extremely limited. Introduction An immediate challenge is deciding which waterflooded pools to include under the "heavy oil" umbrella, as imprecise definitions of heavy oil are used by both government agencies and waterflood operators. Definitions have at times been based on API gravity (a value of = 20 ° API is sometimes used), but often the driving criterion is geography. If a waterflood is located in an area near heavy oil cold production, it is sometimes simply classified as heavy oil, and given to a heavy oil group to operate. Emphasis on an oil-gravity-based definition of heavy oil is convenient, but unfortunate, as it de-emphasizes oil viscosity even though viscosity has repeatedly been shown to be a controlling parameter. Aversion to a viscosity-based definition for heavy oil may be due to occasional problems obtaining consistent heavy oil viscosity measurements(1, 2), and confusion about whether available viscosity values were collected using dead oil, live oil, or something in between. In stark contrast to this general neglect of viscosity data in heavy oil waterflood papers and articles, the most common informal statement about heavy oil waterfloods is, "you can't have a successful heavy oil waterflood if the dead oil viscosity is greater than" a particular value. Values in the 1,000 to 2,000 cp dead oil viscosity range (at reservoir temperature) are often cited as "the limit," but no study establishing a limit appears to exist. Searching the literature for information can be misleading. "Heavy oil" is often used in the title of waterflood articles because conventional oil waterflood technical staff consider oil with viscosity in the range of 3 to 10 cp (much lower than the hundreds to thousands of cp oil more typically waterflooded in Western Canada) to be heavy oil. The technology of Canadian heavy oil waterflooding likely started as conventional oil waterflood theory. It has evolved in a generally empirical manner, and in some ways is still more "art" than "science". The mobility ratio is so adverse that the "flood" process is likely over very quickly. The subsequent process is circulating water which brings enough oil with it for the process to be economic. This much longer "post-flood" period of Western Canadian heavy oil waterfloods is optimized using empirical methods that are often done differently by each oil company, engineer, pumper, etc. The result is a very limited written state of the art.

Horizontal and Multi-Lateral Wells: Performance Analysis-An Art or a Science?

Abstract Several thousand horizontal wells have been drilled around the globe in the last ten years. In Canada alone, horizontal wells have been used in a variety of applications in almost all oil producing provinces. Several hundred multi-lateral wells have also been drilled. There are over 700 multi-lateral wells in Saskatchewan alone. Similarly, underbalanced drilling and coiled tubing drilling are also commonly used. This drilling driven oilfield revolution has made a significant impact on oilfield development. In any oilfield project one is interested in four questions, namely expected well rates, well reserves, well cost, and probability of commercial success or risk factors. Although there are horizontal well projects where commercial success rates are very high, overall commercial success of the technology in North America is about 65%. This is especially of concern since most of the horizontal wells are infill wells. Understanding these successes and failures requires an analysis of well performance. In this article, practical difficulties and solutions for well performance analysis are discussed. Introduction Figure 1 shows schematic diagrams of different horizontal and multi-lateral well configurations. FIGURE 1: Typical horizontal well and multi-lateral well profiles. (Available in full paper) The figure shows that due to advances in drilling technology, it is possible to drill wells with different geometric configurations. Most of the Canadian wells to-date is single lateral horizontal wells. It is becoming common to drill 1,000 to 1,500 m long horizontal wells. Moreover, most of the wells drilled have medium radius build-rates and are completed either with a slotted liner or an open-hole completion. Multi-laterals have been used effectively to improve production as well as injection rate. The majority of the multi-laterals in North America are either open hole or one of the laterals is completed with a slotted liner. With such a completion, it is difficult to measure production from each lateral. Moreover, it is not easy to stimulate each lateral effectively. A coiled tubing may be necessary to enter each lateral independently, which of course adds to the stimulation cost. In some cases, even with coiled tubing it may not be possible to access each leg of the well. In Canada, the major success of horizontal wells has been in producing gas zones, thin heavy oil columns, water-floods, and miscible floods in carbonates. Although many papers are written on SAGD, the field projects are limited to a dozen or so. Only a few have declared that they are commercially successful. One ofthem is the Celtic field in Saskatchewan where a horizontal well produces at 100 m3 /d with oil-stream ratio of about two. Flow Behaviour A horizontal well, similar to a vertical well, when put on production will initially go through a transient flow followed by a well stabilization or a stabilized flow(1). On a log-log plot of rate vs. time, this is observed as two different straight lines with two distinct slopes (Figure 2). Many times, this is also observed on the semi-log plot of rate vs. time.

Application of Statistical Analysis to Optimize Reservoir Performance

Abstract In order to properly manage the depletion of a petroleum reservoir one must understand its physical characteristics and their relationship to production performances. Often the challenge is to interpret an extensive amount of available information. This paper presents an approach to this common petroleum engineering problem using statistical analysis. Statistical analysis can provide an improved understanding of any reservoir. Beginning with the compilation of a comprehensive database, intrinsic relationships among physical parameters and production are characterized. Mapping of statistically processed data allows field-wide interpretation and visual comparison with the geological model. Probabilities of production success can be mathematically determined and used to focus optimization efforts on areas of the reservoir with favourable characteristics. The techniques provide an unbiased appraisal of the available data that can lead to re-examination of assumptions about the underlying mechanisms governing production behavior. Technical hypotheses can be tested for consistency by determining if expected correlations are present in the data. A recent evaluation of the performance of a heavy oil waterflood at Golden Lake, Saskatchewan, is discussed to illustrate the application of the method. Modification of well completion practices and the reservoir depletion strategy have resulted from the study, and favourable areas for infill drilling have been identified. Introduction The initial challenge when analyzing the performance of a petroleum reservoir is often to marshal and interpret an overwhelming amount of raw data. Technological advances in reservoir characterization and data processing have provided access to an abundant supply of numerical data. Coincidentally, the importance of understanding reservoir heterogeneity to maximize depletion efficiency is increasingly recognized. Complex variation of fluid and rock properties within reservoirs is the norm, demanding more detailed description and sophisticated technical analysis. Techniques for processing large databases and distilling critical knowledge are therefore of growing interest to the petroleum engineer. The data overload problem may be addressed by arbitrarily discarding information or by working with averaged values. A compromised between these shortcuts and utilization of all the data available is usually necessary; however, the quality of technical analysis may be sacrificed by over simplification. A method of extracting the important information concealed in an extensive dataset is required. Determination of the significant factors controlling production success will usually suggest the proper course to optimize the field. Statistical analysis techniques are well suited to achieving the objectives. Statistical analysis of data is best regarded as a supplement to, not as replacement for, the engineering analysis typically undertaken to solve technical problems. As an integrated component of a study, it can generate ideas, provide direction, and confirm that the data actually supports the theoretical conclusion. The value added by statistical analysis comes from ensuring no important trends hidden in the data are overlooked, and from the improved level of confidence in the results. Petro-Canada initiated a comprehensive technical review of the Golden Lake heavy oil field in 1994. The scope of the work included standard waterflood analysis, laboratory experiments, field tests, and numerical simulation in conjunction with the statistical analysis discussed in this paper.

Application of Statistical Analysis to Optimize Reservoir Performance

Abstract In order to properly manage the depletion of a petroleum reservoir one must understand its physical characteristics and their relationship to production performance. Often the challenge is to interpret an extensive amount of available information. This paper presents an approach to this common petroleum engineering problem using statistical analysis. Statistical analysis can provide an improved understanding of any reservoir. Beginning with the compilation of a comprehensive database, intrinsic relationships among physical parameters and production are characterized. Mapping of statistically processed data allows field-wide interpretation and visual comparison with the geological model. Probabilities of production success can be mathematically determined and used to focus optimization efforts on areas of the reservoir with favourable characteristics. The techniques provide an unbiased appraisal of the available data that can lead to re-examination of assumptions about the underlying mechanisms governing production behaviour. Technical hypotheses can be tested for consistency by determining if expected correlations are present in the data. A recent evaluation of the performance of a heavy oil waterflood at Golden Lake, Saskatchewan, is discussed to illustrate the application of the method. Modification of well completion practices and the reservoir depletion strategy have resulted from the study, and favourable areas for infill drilling have been identified. Introduction The initial challenge when analysing the performance of a petroleum reservoir is often to marshal and interpret an overwhelming amount of raw data. Technological advances in reservoir characterization and data processing have provided access to an abundant supply of numerical data. Coincidentally, the importance of understanding reservoir heterogeneity to maximize depletion efficiency is increasingly recognized. Complex variation of fluid and rock properties within reservoirs is the norm, demanding more detailed description and sophisticated technical analysis. Techniques for processing large databases and distilling critical knowledge are therefore of growing interest to the petroleum engineer. The data overload problem may be addressed by arbitrarily discarding information or by working with averaged values. A compromise between these shortcuts and utilization of all of the data available is usually necessary; however, the quality of technical analysis may be sacrificed by over simplification. A method of extracting the important information concealed in an extensive dataset is required. Determination of the significant factors controlling production success will usually suggest the proper course to optimize the field. Statistical analysis techniques are well suited to achieving these objectives. Statistical analysis of data is best regarded as a supplement to, not a replacement for, the engineering analysis typically undertaken to solve technical problems. As an integrated component of a study, it can generate ideas, provide direction, and confirm that the data actually supports the theoretical conclusions. The value added by statistical analysis comes from ensuring no important trends hidden in the data are overlooked, and from the improved level of confidence in the results. Petro-Canada initiated a comprehensive technical review of the Golden Lake heavy oil field in 1994. The scope of the work included standard waterflood analysis, laboratory experiments, field tests, and numerical simulation in conjunction with the statistical analysis discussed in this paper.