The Guando field is a late Cretaceous sandstone with two distinct reservoirs with total gross thickness of approximately 1300 feet. Discovered in 2000, the field is Colombia’s largest oil discovery since the mid 1980’s. Due to the low initial reservoir pressure, water injection began almost simultaneously with field development. Water is injected selectively into the main reservoir´s main sands in order to optimize the distribution of injected water. However, oil recovery efficiency is challenged by reservoir heterogeneity, including natural fractures.
The first polymer gel conformance application in Colombia was implemented in 2008 in an effort to improve waterflood sweep efficiency. The objective of the gel treatments was to reduce the permeability in the most conductive natural fractures. The conformance pilot included two non-adjacent patterns. Initially, the design team considered isolating the upper reservoirs and treating only the lower reservoirs. However, in the final design both treatments were “bullheaded” with all zones open to gel injection. The treatment designs included several stages of varying gel concentrations and injection rates, which were modified in the course of each treatment application based on surface pressure response.
Post treatment oil response occurred within approximately two months and payout was achieved in less than six months, driving new candidate selection and treatment in 2013. The paper will discuss the reservoir diagnostics that led to the selection of polymer gel as the most effective solution to severe water channeling. Also, we will present plans for additional gel treatments with an emphasis on cost reduction and improved treatment designs.
Polymer gels have been successfully applied in naturally fractured reservoirs for almost two decades, however, reservoir characterization tools continue to evolve, providing more precise diagnostics that offer improved conformance treatment designs. This case history will provide an updated framework for operators considering chemical sweep improvement technologies as part of an integrated field management strategy.
Low salinity waterflooding is gaining some attention in the recent literature as a means of improving oil recoveries. However, a clear understanding of the key mechanism(s) of low-salinity waterflooding does not seem to have emerged although wettability alteration is repeatedly cited as the cause for the observed effects, albeit without much experimental evidence. Moreover, much of the reported low-salinity work appears to be related to sandstone reservoirs.
In this study, we have attempted to investigate the role wettability alteration plays in low-salinity waterflooding by conducting dual-drop-dual-crystal contact angle measurements to characterize wettability changes and coreflood experiments for oil recovery and oil/water relative permeability measurements using a dolomite reservoir rock-fluids system. Additional experiments have been conducted to examine the roles of brine chemistry and the temperature in altering wettability in low-salinity waterfloods.
The contact angle results clearly indicate the wettability alteration from an oil-wet state (with a water-advancing contact angle of 158o) to an intermediate state (with an advancing contact angle of 113o) caused by diluting the reservoir brine to one-fiftieth of its original strength. A similar result was obtained when the sulfate concentration in the reservoir brine was doubled and when the temperature was increased to 250oF from the reservoir temperature of 80oF. These wettability alterations as measured by contact angles were confirmed by coreflood experiments that yielded significantly higher recoveries (from about 46% to about 76%) due to low-salinity flooding, alteration of brine composition and temperature.
This experimental study confirms the major influence of wettability in low-salinity waterflooding of a dolomite reservoir.
For the first time ever a novel biopolymer is being field tested in a mature onshore oil field in Northern Germany. This biopolymer - named Schizophyllan after its producing fungus - shows excellent viscosifying efficiency and high tolerance towards harsh reservoir conditions such as high temperature, salinity and shear. Hence, this biopolymer allows for application in reservoirs that could so far not be easily polymer flooded and extends the operating envelope for polymer flooding to temperatures up to 130°C at arbitrary salt contents. Furthermore, it provides an environmentally friendly alternative to the commonly used synthetic polymers.
To run this first field test petroleum engineers of Wintershall Holding GmbH, chemical research scientists and biotechnologists of BASF SE are closely cooperating in an integrated team. An existing biotechnological plant at the BASF compound in Ludwigshafen, Germany, was partly reconstructed into a production facility for the biopolymer providing sufficient material for the field pilot. In the oil field itself an existing production site was extended into an operation site also hosting the surface facilities for treatment of the produced water used for re-injection and preparation of the injected biopolymer solution.
Being trucked to site as mother solution the Schizophyllan is mixed on-the-fly with the treated, high-salinity reservoir brine and injected into a newly drilled injector in the project area surrounded by three production wells. A comprehensive surveillance programme was set up comprising regular microbiological sampling, pressure monitoring using permanent down-hole gauges as well as frequent analyses and production tests to monitor the progress of the polymer trial.
The paper presents further information on the biopolymer Schizophyllan, describes the preparation and the setup of the field trial and summarizes results and experiences from the first year of the two-year field trial.
A large amount of hydrocarbon fluids in shale formations are stored within the organic matters where the pore sizes are in nanometer scales. Inside these nanopores, the fluid-wall interactions play such an important role that can change the phase behavior and transport mechanisms of the fluids. However, current available equations of state do not account for such interactions.
This work focuses on modifying Peng-Robinson equation of state (PR-EOS) using simplified local-density theory. First of all, density profiles of the hydrocarbon fluids are calculated along the pore diameter for difference pore sizes. From the density profile one can distinguish the regions of adsorbed phase, transition phase and bulk phase of the fluids. The phase behavior and transport properties of the fluids such as viscosity and diffusion coefficient are then calculated in each region from the modified PR-EOS using the averaged fluid properties in that particular region.
Our results showed that depending on fluid composition, either single layer or multilayer adsorption is presented in those nanometer pores near the pore wall. The pore size range we focused on was from 20 to 2 nm. When the pore size gets smaller and smaller, the absorbed layers at opposite pore walls are merged into one layer and result in the absence of the bulk fluid phase in the center areas of the pores. In such case all the fluids in the pore are under influence of the wall. For a synthetic mixture of 75% methane, 20% n-butane and 5% n-octane, the results indicate that for smaller pores, the bubble point and dew point pressures of the adsorbed hydrocarbon fluids are 50 to 500 psi lower than the bulk values and the two-phase region shrinks. Our analysis also showed that fluid viscosity started to increase significantly by approximately one fold when pore size is below 5 nm.
As results show, the hydrocarbon fluids under confinement tend to behave similar to dry gas. This reduces condensate banking and near-wellbore permeability impairment in comparison to conventional approaches. It has several implications for prediction of reservoir and well performance by implementing it into a numerical reservoir simulation package.
Modeling of enhanced / improved oil recovery processes that takes into account mass transfer between phases depends on the correct prediction of thermodynamic properties and composition of phases in equilibrium. In a steam flood process, the mutual water / hydrocarbons solubility depends on the temperature, pressure and fluid composition and may not be negligible at flooding conditions. The most used equations of state in petroleum industry fail to accurately correlate saturation properties of polar substances that self-associate through hydrogen bonding and as a consequence, do not calculate the distribution of the components among equilibrium phases precisely. In this paper we present the development of the Association Peng-Robinson and Soave-Redlich-Kwong equations of state. The proposed equations of state are composed of two parts, one physical (the original cubic equation of state model) and one chemical (an empirical chemical reaction accounting for self-association of a component) and can be used to model the systems in equilibrium containing one associating component, like water or alcohol.In the extended equations of state, the molar volume polynomial is modified from the original degree three to six. The chemical part of the extended EoS includes three adjusting parameters, the entropy and enthalpy of the association chemical reaction and one free parameter. The fugacity calculations for the extended EoS can be split into physical and chemical parts, where the physical part has the same form as the original equations of state. In order to estimate the new parameters, the differences between the experimental and calculated saturation pressure and saturated liquid molar volume of pure water are minimized using a Particle Swarm Optimization algorithm.The average relative deviation between the experimental and calculated saturated data using the association forms of the Peng-Robinson and Soave-Redlich-Kwong equations of state are smaller than those obtained from the original models.The chemical reaction approach is robust and improves the prediction of thermodynamic equilibrium properties of self-associating pure components by adding only three adjustable parameters.
Gamadi, T.D. (Texas Tech University) | Sheng, J.J. (Texas Tech University) | Soliman, M.Y. (Texas Tech University) | Menouar, H. (Texas Tech University) | Watson, M.C. (Texas Tech University) | Emadibaladehi, H. (Texas Tech University)
An article by Hart (2011) quoted one of EOG resources recent reports that recovery factor for the Eagle Ford shale play during primary drive reservoir depletion will be roughly 5%. The vast oil remaining stimulates our efforts to investigate the application of enhanced oil recovery methods in shale oil reservoirs. Recent numerical studies have indicated that cyclic gas injection could be an effective method to increase the oil recovery of shale oil reservoirs.
Cyclic gas injection could be an effective technique because it is a single-well process; well-to-well connectivity is not required. The hydraulic fracturing provides a large contact area for the injected gas to penetrate and diffuse into the low-permeability matrix. The payback period of the cyclic gas injection process is rather short compared with that of the field- scale flooding process. This makes the single-well cyclic injection process a low-risk process.
This paper presents our experimental verification and quantification of the potential of using cyclic CO2 injection in shale oil reservoirs. This work is the first experimental work to investigate the performance of CO2 huff-n-puff on shale cores. Core plugs of Mancos and Eagle Ford shales were used. A special lab set up was built to conduct this study. The effects of cyclic time (Soaking Period) and injection pressure on oil recovery, among other parameters, were investigated. Our experimental results showed that cyclic CO2 injection could increase the recovery factor from 30% to 70% depending on the shale core type. It also shows the effect of the pores connectivity and heterogeneity on the performance of CO2 huff-n-puff. This study shows that one of the important mechanisms of cyclic gas injection is the pressure effect that causes a large pressure drawdown during the production phase.
In a CO2 EOR project the injected CO2 seldom sweeps all portions of each injection pattern uniformly. This is compounded by the fact that injection patterns are not always symmetrical and the injector itself may not be centered within the pattern. Areal sweep within a pattern is further influenced by pressure gradients which may not be uniform in all directions.
At the SACROC unit the approach to maximizing the areal sweep involves detailed monitoring of individual producing well pump intake pressures and producing GOR’s as well as the calculated streamlines to identify opportunities for changing the direction of CO2 migration in the reservoir. It is frequently observed that response to CO2 injection occurs in only one well or only one side of a pattern with little to no effect in the other directions. The remedy presented in this paper involves converting to flow or slowing down the pump in the responding wells (and thus raising the pump intake pressure) when their GOR exceeds a certain threshold and upsizing or speeding up the pumps in the wells on the opposite side of the pattern.
The effect of these changes is to alter the pressure distribution within the pattern and change the portion of the reservoir being processed by CO2. We have documented cases where the pattern recovery has more than doubled due to altering the streamlines in this manner. This technique of monitoring and altering the streamlines is time and data intensive but in the patterns where it is applicable significant increases the ultimate EOR recovery can be obtained for essentially zero capital cost.
This paper discusses the pattern selection criteria, data requirements, and the timing and method of adjusting the withdrawal rates to alter the streamlines and increase areal sweep efficiency.
The following paper is a field case study of conformance engineering efforts completed in the West Sak field over the last 8 years. The West Sak field is a shallow viscous oil reservoir with poorly consolidated sand that has been under waterflood since 1998. Due to the nature of the formation and the completion techniques used, the field has observed some severe conformance issues. We will review the conformance candidate identification and selection criteria, followed by an overview of additional problem characterization efforts. We will review a variety of solution designs considered and attempted, and summarize some lessons learned from both our failures and success’s during this effort. This review will discuss treatments that range from pumping graded CaCO3, Molten Wax, Special Cement blends, and finally PPG (Preformed Particle Gels) or water swelling polymer crystals. A majority of these treatments have been executed on horizontal wells which also creates some challenging placement control dynamics. We will review some of our efforts to control those placement dynamics, and discuss some of the potential problems associated with that control. Ultimately we will describe the evolution of our current solution treatments and provide a brief economic review of the overall performance of this effort.
Bati Kozluca Field is a heavy oil carbonate reservoir discovered in 1985; it is located in the South East of Turkey, close to Syria border. The reservoir began primary production in 1985, developed with 41 wells producing 12.6 API oil. Main constraints for oil recovery are the low aquifer support, low solution gas oil ratio and high oil viscosity which is 480 cp at reservoir conditions. In order to increase 5% recovery, full field continuous immiscible CO2 injection had been implemented from 2003 to 2007 and full field IWAG injection had been implemented from 2007 to 2012. These projects increased the oil recovery from 5% to 6.7% and increased the daily oil production two times. In 2012, it was decided to re-develop the field to increase the 6.7% recovery.
This paper first gives the results of the CO2 and IWAG applications in the Bati Kozluca Heavy Oil Field and then describes the field-wide simulation study conducted to predict the future reservoir performance of the black oil simulation model under various operating and development strategies. First, available data is screened and quality of the data is evaluated; then, dynamic model is built. The model has been successfully history matched with 27 years of production, injection, saturation and pressure history on both the field and the well scale. The history matched model is used to decide the methodology and to determine the infill well locations, injection pattern and injection schemes to increase the oil recovery. Simulation results show that recovery can be increased from 6.7% to 9% with the current injection pattern and without any investment by continuing the project with the optimized injection parameters. However, injection pattern needs to be modified to increase the volumetric sweep efficiency and oil recovery.
When both Fe(II) and oxygen are present in aqueous HPAM solutions, redox couples can substantially degrade polymers. In the absence of dissolved oxygen and oxidizing agents, HPAM can be quite stable in the presence of Fe(II). HPAM can also be reasonably stable in the presence of dissolved oxygen in the absence of Fe(II) and free-radical generating impurities, if certain conditions [oxidation-reduction potential (ORP), pH, brine composition, temperature] are met. In field applications of chemical flooding, a gray area exists where significant iron (either solid or dissolved) may be present, along with low levels of dissolved oxygen (e.g., <50 parts per billion, ppb). Large differences of opinion exist on how to treat this situation, including (1) removing all iron, (2) removing all dissolved oxygen, (3) addition of free-radical scavengers or adjustment of ORP and/or pH, and (4) no action.
This paper describes an experimental study of stability of an HPAM polymer and an HPAM-AMPS terpolymer with varying initial levels of dissolved oxygen (0, 10, 20, 50, 200, 500, 2000, and 8000 ppb), Fe(II) (0, 1, 5, 10, 20, 30, 50, 100, and 500 parts per million, ppm), and Fe(III) (0, 1, 5, 10, 50, 100, and 500 ppm). A special method was developed to attain and confirm dissolved oxygen levels. Stability studies were performed at 23°C and 90°C.
With ≤2000 ppb initial O2, the dissolved oxygen dropped to 0 ppb within one week. Our findings reveal that once the available dissolved oxygen is depleted, no further oxidative degradation of polymer occurs. The results were insensitive to Fe(II) concentration for initial O2 ≤2000 ppb. For initial O2 of 8000 ppb, polymer degradation increased significantly with increased Fe(II). Solution viscosity losses were insignificant for O2 concentrations of 500 ppb or less.
In the studies with Fe(III), the iron crosslinked the polymer to form a visible gel. However, in the studies with Fe(II), we saw no evidence of gel formation, suggesting when Fe(II) reacted with O2, any Fe(III) that formed was converted to solid iron oxide before any polymer crosslinking could occur. The significance of these observations for field applications will be discussed.