bluuebunny/crossref_metadata_2025 huggingface dataset:
Optimal Rate Control Under Geologic Uncertainty
Authors: Alhuthali Ahmed H. , Datta-Gupta Akhil , Yuen Bevan , Fontanilla Jerry P.
Published: April 2008

Waterflood optimization via rate control is receiving increased interest because of rapid developments in the smart well completions and i-field technology. The use of inflow control valves (ICV) allows us to optimize the production/injection rates of various segments along the wellbore, thereby maximizing sweep efficiency and delaying water breakthrough. A major challenge for practical field implementation of this technology is dealing with geologic uncertainty. In practice, the reservoir geology is known only in a probabilistic sense; hence, the optimization of smart wells should be carried out in a stochastic framework to account for geologic uncertainty.

We propose a practical and efficient approach for computing optimal injection and production rates accounting for geological uncertainty. The approach relies on equalizing arrival time of the waterfront at all producers using multiple geologic realizations. The main objective is to improve sweep efficiency and thereby improve oil production and recovery. We account for geologic uncertainty using two optimization schemes. The first one is to formulate the objective function in a stochastic form which relies on a combination of expected value and standard deviation combined with a risk attitude coefficient. The second one is to minimize the worst case scenario using a min-max problem formulation. The optimization is performed under operational and facility constraints using a sequential quadratic programming approach. A major advantage of our approach is the analytical computation of the gradient and Hessian of the objective function which makes it computationally efficient and suitable for large field cases.

Multiple examples are presented to support the robustness and efficiency of the proposed optimization scheme. These include 2D synthetic examples for validation and a 3D field-scale application. The role of geologic uncertainty in the outcome of the optimization is demonstrated both during the early stage and also, later stages of waterflooding when substantial production history is available.
A Combinatorial Approach for Identification of Performance EOR Surfactants
Authors: Morvan M. , Koetitz R. , Moreau P. , Pavageau B. , Rivoal P. , Roux B.
Published: April 2008

This work describes an automated combinatorial process for selecting EOR surfactants. It is well known that low interfacial tension (IFT) required to mobilize oil corresponds to the appearance of middle phase microemulsions (Winsor III). Instead of systematic measurements of IFT, simple observation of phase behaviour in vials allows to select best formulations. As the number of parameters to be screened incorporate surfactants, co-surfactants, alkali and electrolytes, we have developed an automated method to accelerate the screening productivity. Among other requirements, critical issues we want to address concern compatibility with electrolyte, thermal stability and low cost.

Sample preparation is done in 48 well format using a robotic liquid handling platform that supports stirring and heating. In a first step, the brine concentration above which the surfactant is not soluble anymore is determined optically using a digital camera. In a second step, we take images of the phase behaviour of surfactant formulations in the presence of model oil (dodecane, vaseline). Image analysis is used to detect middle phase microemulsions. An estimate of interfacial tension can be derived from the volume of the middle phase microemulsion. Phase diagram observations can be recorded from room temperature up to 80°C. Results are in good agreements with classical methods used to measure low interfacial tension. An example study of phosphate esters will be discussed to illustrate the method.

This technique provides a powerful tool for testing formulations prior to more expensive core flood experiments.
Application of pH-Triggered Polymers in Fractured Reservoirs to Increase Sweep Efficiency
Authors: Lalehrokh Farshad , Bryant Steven L. , Huh Chun , Sharma Mukul M.
Published: April 2008

Water and gas shutoff in naturally fractured reservoirs is traditionally achieved with cross-linked gels. Low sweep efficiency is also an important problem in waterflooding such reservoirs which can be treated with gel. In-depth placement of gels is the key to success, and this requires careful control of the cross-linking chemistry. This work examines the feasibility of an alternative gelation mechanism in fractured rock: pH-triggered polymer microgels. The microgel particles are small enough to pass through fractures but not pore throats in a matrix. The pH change occurs naturally and inevitably; it thus offers a simpler means of obtaining deep placement.

When an acidic polymer solution is injected into the formation, several factors affect the pH: rock mineralogy, reactive surface area of the minerals, temperature and dilution due to mixing with residual water. The viscosity of the solution depends strongly on pH and upon polymer concentration and salinity of the polymer solution. The rate of pH increase relative to the rate of fluid advance determines the depth of placement.

We used commercially available polymers which exhibit low viscosity at a pH below 3 but transform to gels at pH > 4. Polymer solutions were injected through artificial fractures in outcrop cores. Both sandstone and carbonate rocks raise the polymer solution pH. The presence of acid-soluble minerals containing cations such as calcium can independently trigger viscosification by precipitating the polymer. After polymer injection, a shut-in time allows further reaction to increase the pH and thus affects the Permeability Reduction Factor (PRF), the ratio of original fractured core permeability to treated core permeability. The PRF was measured to be in the range of 200 to 5 during the various experiments. The gelation is faster and PRF is higher in carbonates than in sandstones. Because the neutralization capacity of a core is large, it is possible to approximate reactive transport in a reservoir by continuously re-circulating the polymer effluent. Experiments showed gellike characteristics after 30 pore volumes of recirculation in Berea sandstone.
An Innovative Approach to Evaluate Residual Oil Saturation in Insitu Condition
Authors: Hazra S. , Bhattacharya S.
Published: April 2008

Residual oil Saturation plays a big role in simulation study for forecasting oil production. Generally it is determined through core flood experiments under reservoir conditions in small core plugs which do not capture the actual reservoir heterogeneity. More over it uses dead crude oil after matching the reservoir oil viscosity. Due to this, it is often difficult to generate representative ROS distribution throughout the field. There are other methods reported in the literature having some inherent limitations.

Cased hole formation resistivity, a relatively new technology introduced in the industries to know the by passed oil in mature fields. It is mainly used for re-completion of old producing wells either through zone transfer or placement of horizontal wells. In this paper use of Cased hole formation resistivity in injectors having long injection history are conceptualized with the aim to get remaining oil saturation with respect to water injection in the formation. Due to prolong water injection / flushing it is expected that maximum water intake zone will show the oil saturation close to the residual oil saturation.

The present paper discussed the results of two injectors where Cased hole formation resistivity along with injection profile were recoded. The oil saturation in the maximum water intake zone was compared with the residual oil saturation determined through laboratory established correlation based on core flood studies.

The results indicate that the oil saturation is much lower than the core flood ROS in the reservoir area where maximum water has been injected. This adds a new dimension in determining the in-situ measurement of ROS. The interpretation issues like effect of injected water salinity etc are also illustrated in the paper.
EOR Potential of the Michigan Silurian Reefs Using CO2
Authors: Toelle Brian , Pekot Larry , Barnes David , Grammer Mike , Harrison William
Published: April 2008

The Guelph Formation, historically known as the Brown Niagaran, is a Silurian age formation in the Michigan Basin containing hundreds of pinnacle reefs. These reefs, discovered primarily during the 1970s, have produced nearly half a billion barrels of primary oil. Over 700 reefs make up the northern trend and more than 300 reefs have been located in the southern portion of the basin, many of which have produced more than 5 MM bbls of oil. The EOR potential of these fields is believed to be significant. Few of these fields have been waterflooded and only five have experienced CO2 injection.

An ongoing US Department of Energy project is studying the use of CO2 in enhanced oil recovery operations at the Charlton 30/31 reef, which is located in Michigan's Otsego County. This field was discovered in 1974 by Shell and produced 2.6 million bbls of oil during its primary production phase from a reservoir that may be typical of the other reefs in these trends. The reservoir is composed of a limestone matrix with low porosity and low permeability that contains irregular dolomitized intervals. These dolomitized zones, with higher porosity and permeability, control the flow of fluids through these reservoirs. This project utilized 4D seismic, reservoir simulation and a new well drilled into the reef to provide greater understanding of the CO2 EOR potential for this and all of the Silurian reefs in Michigan.
Selection and Screening of Polymers for Enhanced-Oil Recovery
Authors: Levitt David B. , Pope Gary A.
Published: April 2008

A number of commercially available polymers have been tested for enhanced oil recovery based upon viscosity, filterability, and surfactant compatibility, and chemical and thermal stability testing has been carried out with some of these as well. Several high molecular weight polymers exhibited high viscosities at salinities up to 170,000 ppm NaCl and with greater than 17,000 ppm CaCl2 present. Polyacrylamide polymers hydrolyze at high temperatures and beyond a certain point are subject to precipitation by calcium. If calcium concentrations can be kept below about 200 ppm, the use of polyacrylamide polymers is feasible up to reservoir temperatures of at least 100°C. For higher concentrations of calcium, copolymers including AMPS moieties should be considered. Calcium tolerance can be improved with sodium metaborate or by using copolymers of acrylamide and sodium 2-acrylamido-2-methylpropane sulfonate (AMPS). The stability problems at elevated temperatures in the presence of iron can be mitigated by the use of chemicals such as sodium dithionite and sodium carbonate. The polymers tested did not lose viscosity after 220 days of aging at 100°C with dithionite present.
Designing for Mixed Wettability
Authors: Kumar M. , Senden T. J. , Latham S. , Sheppard A. P. , Knackstedt M. A. , Cinar Y. , Pinczewski W. V.
Published: April 2008

In this paper we describe a technique based on radio frequency plasma treatment in H2O vapour to reproducibly clean and modify the surface energy of clastic and carbonate core material allowing the establishment of well defined wettability conditions. We present micro-tomographic observations of the pore-scale fluid distributions in strongly water wet clastic and carbonate cores. We then establish mixed-wet states in the same cores using controlled hydrophobation. Micro-tomography is again used to reveal the three-dimensional geometry and topology of water and oil wet regions. The tomographic data shows that under water wet conditions at intermediate saturations larger pores are predominantly oil filled while smaller pores remain water wet. We perform displacement experiments using clastic and carbonate cores at well defined wettability conditions and report measurements of resistivity index. These methodologies may provide insight into the role of rock microstructure and surface energy variability in determining recovery and production characteristics of oil and gas reservoirs.
Pore-Scale Simulation of WAG Floods in Mixed-Wet Micromodels
Authors: van Dijke M. I. J. , Lorentzen M. , Sohrabi M. , Sorbie K. S.
Published: April 2008

In this paper the simulation is described of water-alternating-gas injection (WAG) flood cycles in 2-D etched glass mixed-wet micromodels, using a 3-D pore-scale network model for three-phase immiscible flow in porous media of arbitrary wettability. Although most network model input parameters can be explicitly derived from the experiments, the precise wettability parameters are not directly available. Therefore, a sensitivity study was carried out, using the network model in 2-D mode, to obtain the wettability characteristics, i.e. the contact angle values and distribution, and the fraction of water-wet pores. Good qualitative and quantitative agreement was found between the experimental and simulated recoveries over the various WAG cycles, and the final residuals were well reproduced (as well as some observed "random recovery jumps"). The simulated displacement statistics showed many so-called multiple displacement chains involving oil, up to around the third WAG cycle. The experimental and simulated fluid distributions were generally in good agreement in that (a) different gas fingers were observed during various gas floods, (b) oil movement was observed mainly during the first few WAG cycles, and (c) during water floods, significant amounts of gas were displaced. Additionally, previously described simulations of water-wet and oil-wet experiments are compared with the present mixed-wet simulations. There are close similarities between the mixed-wet and oil-wet cases, which both maintain some continuity of oil through wetting films, but these cases are quite different from the water-wet case, which has continuity of water through wetting films in all pores. This paper further validates the pore-scale mechanisms incorporated in a network model that is capable of predicting three-phase relative permeabilities and capillary pressures for complicated processes such as WAG.
Evaluation of Behind-Pipe Saturation in a Miscible CO2 Flood
Authors: Amadi Samuel , Hughes Richard G.
Published: April 2008

To evaluate the amount of bypassed oil in a CO2 flood, it is necessary to obtain some estimate of the remaining oil saturation. Near wellbore oil saturation determination requires a tool or sequence of tools that is able to distinguish oil from other phases that may be present in situ especially when those phases are miscible with the oil.

This paper presents the combined use of several neutron tools to evaluate the remaining oil saturation in a miscible CO2 flood. These techniques are not time lapse techniques and so are applicable even where there are no base cased-hole logs to evaluate.

These methods are applicable in areas where CO2 has been injected for a long period of time without a base pre-CO2 log. The techniques work best with a full suite of open-hole logs to characterize the petrophysical properties of the well and where heterogeneity effects control the displacement process. If petrophysical properties are known or reasonably estimated from other data available, the proposed methods can provide an estimate to the oil saturation that should be adequate to allow go/no go decisions.
Foam Mobility Control for Surfactant EOR
Authors: Li Robert Feng , Yan Wei , Liu Shunhua , Hirasaki George J. , Miller Clarence A.
Published: April 2008

Foam generated in situ by surfactant alternated with gas injection is demonstrated as a substitute for polymer drive in the alkaline-surfactant-polymer (ASP) EOR process. Foam is also effective in a similar process for a 266 cp crude oil, even though the system did not have enough polymer for favorable mobility control. Foam is shown to greatly enhance sweep efficiency in a layered sandpack with a 19:1 permeability ratio. Foam diverted surfactant solution from the high-permeability layer to the low-permeability layer. Ahead of the foam front, liquid in the low-permeability layer crossflowed into the high-permeability layer. A layered system with a 19:1 permeability contrast could be completely swept in 1.3 TPV (total pore volume) with foam while waterflooding required 8 PV (pore volume).
Air Foam Injection for IOR: from Laboratory to Field Implementation in ZhongYuan Oilfield China
Authors: Yu Hongmin , Yang Baoquan , Xu Guorui , Wang Jiexiang , Ren Shao Ran , Lin Weimin , Xiao Liang , Gao Haitao
Published: April 2008

The Hu-12 Block, located in ZhongYuan Oilfield, Henan Province China, contains many small but highly heterogeneous oil reservoirs, with low permeability oil bearing formations and high permeability mixed (oil/water) layers. The reservoir temperature is 90 °C, and the original reservoir pressure of nearly 25 MPa, and with high salinity of formation water (around 200,000 mg/l). After 20 years of water injection, the recovery factor achieved was only 20–25%, and average water cut has reached to over 95%. N2 gas injection has been tried with less success due to early gas breakthrough from high permeability zones. Since 2006, high pressure air foam and air injection (Air Foam Alternative Air Injection, AFAAI) has been proposed and implemented in one of the reservoirs, in order to block high permeability water zones and increase the sweeping efficiency of air and water injection. A series of laboratory experiments have been conducted to study the oxidation kinetics of air/air foam with oil and the blocking and displacement efficiency of air foams in different oil sands. Reservoir simulation has also been carried out for predicting the reservoir response to air foam injection and optimizing the injection process. Air foam and air injection was started in the field since May 2007 in a well group with 1 injector and 4 producers, using a small high pressure air compressor (40 MPa, 7 m3/min air rate). Up to now, 460,000 Nm3 air and 2920 m3 foam surfactant solution have been injected into the reservoir. The field results show that no oxygen/N2 breakthrough was observed and a significant increase in oil production with water cut reduced by 4%. The detailed laboratory study and field experience are presented in this paper.
The Modeling Challenge of High Pressure Air Injection
Authors: de Zwart A. H. , van Batenburg D. W. , Blom C. P. A. , Tsolakidis A. , Glandt C. A. , Boerrigter P.
Published: April 2008

High Pressure Air Injection (HPAI) is a potentially attractive enhanced oil recovery method for deep, high-pressure light oil reservoirs after waterflooding. The advantage of air over other injectants, like hydrocarbon gas, carbon dioxide, nitrogen, or flue gas, is its availability at any location. HPAI has been successfully applied in the Williston Basin for more than twenty years and is currently being considered by many operators for application in their assets.

Evaluation of the applicability of HPAI requires conducting laboratory experiments under reservoir temperature and pressure conditions to confirm crude auto-ignition and to assess the burn characteristics of the crude/reservoir rock system. The ensuing estimation of the potential incremental recovery from the application of HPAI in the reservoir under consideration requires fit-for-purpose numerical modeling. Typically, the flue gas generated in-situ by combustion leads to in an immiscible gas drive, where the stripping of volatile components is a key recovery mechanism. HPAI has therefore, in some instances, been modeled as an isothermal flue gas drive, employing an Equation of State (EOS) methodology. This approach, however, neglects combustion and its effects on both displacement and sweep. Furthermore, the EOS approach cannot predict if, and when, oxygen breakthrough at producers occurs. Combustion can be included in a limited fashion in simulations at the expense of extra computational time and complexity. In the available literature, combustion is taken generally into account under quite simplified conditions.

This paper addresses the role that combustion plays on the incremental recovery of HPAI. Numerical simulations were conducted in a 3D model with real geological features. In order to capture more realistically the physics of the combustion front, a reservoir simulator with dynamic gridding capabilities was used. Kinetic parameters were based on the combustion tube laboratory experiments. The impact of combustion on residual oil, sweep efficiency and predicted project lifetime is presented by comparing isothermal EOS-simulations and multi-component combustion runs.
Insurance Value of Intelligent Well Technology against Reservoir Uncertainty
Authors: Addiego-Guevara E. A. , Jackson M. D. , Giddins M. A.
Published: April 2008

Significant challenges remain in the development of optimized control techniques for intelligent wells, particularly with respect to properly incorporating the impact of reservoir uncertainty. Most optimization methods are model-based and are effective only if the model can be used to predict future reservoir behavior with no uncertainty. Recently developed schemes, which update models with data acquired during the optimization process, are computationally very expensive.

We suggest that simple reactive control techniques, triggered by permanently installed downhole sensors, can enhance production and mitigate reservoir uncertainty across a range of production scenarios. We assess the implementation of an intelligent horizontal well in a thin oil rim reservoir in the presence of reservoir uncertainty, and evaluate the benefit of using two completions in conjunction with surface and downhole monitoring. Three control strategies are tested. The first is a simple, passive approach using a fixed control device to balance inflow along the well, sized prior to installation. The second and third control strategies are reactive, employing intelligent completions that can be controlled from the surface. The second strategy opens or closes the completions according to well water cut and flow rate and individual downhole rate and phase measurements obtained from a surface multiphase flowmeter and alternating zonal well tests. The third strategy proportionally chokes the completions as increased completion water cut is measured using downhole multiphase flowmeters.

A cost-benefit analysis demonstrates that reactive control strategies always yield a neutral or positive return, whereas a passive, model-based strategy can yield negative returns if the reservoir behavior is poorly understood. While reactive control strategies enhance production and mitigate reservoir uncertainty, they may not deliver the optimum possible solution. Proactive control techniques, which additionally incorporate data from downhole reservoir-imaging sensors, may yield near- optimal gains.
Kuparuk MWAG Project after 20 Years
Authors: Shi Wen , Corwith Jeff , Bouchard Andre , Bone Russ , Reinbold Eric
Published: April 2008

Through many phases of expansion, the Kuparuk hydrocarbon miscible water-alternating-gas (MWAG) project has grown from 10 patterns on 2 drillsites (Small Scale EOR, or SSEOR) to today&s 283 patterns on 32 drillsites. It now covers an area with almost 4 billion barrels of STOOIP and has generated an estimated 120 MMSTB of incremental oil sales.

The original goals of the MWAG project were twofold: First, there being no available market for produced gas, to efficiently store associated gas in the reservoir (avoiding the rapid recycling of gas observed with other processes); and second, to generate incremental tertiary oil production. The project is approaching its target maturity, especially in the C sand. But the lower throughput A sand has some immature patterns showing lower-than-expected tertiary oil response. Despite the relative maturity of the MWAG flood, expansion opportunities still exist. Based on fine grid compositional simulation, an expansion of MWAG to drillsite "A" is under evaluation.

This paper provides a brief review of the Kuparuk MWAG project&s history, an overview of current status and flood management practices, and describes the latest investigation into further expansions.
ASP Processes: Wide Range of Conditions for Good Recovery
Authors: Liu Shunhua , Li Robert Feng , Miller Clarence A. , Hirasaki George J.
Published: April 2008

Design of an alkaline-surfactant-polymer (ASP) process requires knowledge of the amount of soap formed under alkaline conditions from naphthenic acids in the crude oil. We show here for several crude oils that the acid number determined by nonaqueous phase titration is approximately twice that found by hyamine titration of a highly alkaline aqueous phase used to extract soaps from the crude oil. This acid number by soap extraction should provide a better estimate than nonaqueous phase titration. This soap interacts with the injected surfactant to form surfactant films and microemulsion droplets during an ASP process.

In a previous paper (Liu et al., 2006), an unusually wide range of salinities of ultra-low oil-water interfacial tensions (IFTs) was found for one alcohol-free crude oil/anionic surfactant system under alkaline conditions where naphthenic soaps were present. This surprising and favorable behavior has now been found to exist with the same surfactant blend and another crude oil.

In the same paper, a one-dimensional simulator for the ASP process was presented. Here this ASP simulator has been used for various acid contents, injected surfactant concentrations, slug sizes and salinities to show that high recoveries of waterflood residual oil (>90%) can be expected for a wide range of near-optimal (Winsor III) and under-optimum (Winsor I) conditions for a constant salinity process, even with relatively small slug sizes. A key factor leading to this good performance is development of a gradient in soap-to-surfactant ratio, which assures that a displacement front with ultralow IFT forms and propagates through the formation. Similar high recoveries can be attained for certain over-optimum (Winsor II) conditions but only for much larger slug sizes owing to the tendency for surfactant to partition into the oil phase and become retarded. Large dispersion such as might be expected for field conditions can significantly reduce recovery for small surfactant slugs even for near- optimal and under-optimum conditions. However, this problem can be overcome by injecting the slug and/or drive at salinities below reservoir salinity, thereby creating a salinity gradient.
Time-Dependent Injectivity During CO2 Storage in Aquifers
Authors: Burton McMillan , Kumar Navanit , Bryant Steven L.
Published: April 2008

Economic considerations are likely to drive operators of geologic storage projects to inject as much CO2 as possible into the smallest number of wells. In practice, then, a CO2 injection well is likely to run at the largest bottomhole pressure that is safe. However, a constant-pressure well exhibits a varying rate of CO2 injection because of classical multiphase flow effects, and also because long-term injection of CO2 dries out the near-wellbore region. Drying removes water but precipitates dissolved salts, so the permeability of the dry rock need not equal the initial aquifer permeability. In addition to mobility of CO2 in the dried rock, the injectivity depends strongly on the mobility of the two-phase flow region. The difference in injectivity for seven different measured CO2-brine relative permeability curves is substantial. Characterizing relative permeability will therefore be an important consideration for the practical implementation of CO2 storage projects. The analytical expressions developed here show that injectivity variation can be understood in terms of phase mobilities and the speeds of saturations fronts. The expressions can refine the estimate of the number of wells needed for a target overall injection rate. Well count in turn strongly affects the economics of sequestration projects.
Impact of Phase Behavior Modeling on In-Situ Combustion Process Performance
Authors: Kristensen M. R. , Gerritsen M. G. , Thomsen P. G. , Michelsen M. L. , Stenby E. H.
Published: April 2008

To facilitate the study of reactive-compositional porous media processes we develop a virtual kinetic cell (single-cell model) as well as a virtual combustion tube (one-dimensional model). Both models are fully compositional based on an equation of state. In this work, we apply the models to analyze phase behavior sensitivity for in-situ combustion, a thermal oil recovery process.

For the one-dimensional model we first conduct sensitivity analyses to numerical discretization errors and provide grid density guidelines for proper resolution of in-situ combustion behavior. A critical condition for success of in-situ combustion processes is the formation and sustained propagation of a high-temperature combustion front. Using the models developed we study the impact of phase behavior on ignition/extinction dynamics as a function of the operating conditions. We show that when operating close to ignition/extinction branches, a change of phase behavior model is likely to shift the system from a state of ignition to a state of extinction or vice versa. For both the rigorous equation of state based and a simplified, but commonly used, K-value based phase behavior description we identify areas of operating conditions which lead to ignition. For a particular oil we show that the simplified approach overestimates the required air injection rate for sustained front propagation by 17% compared to the equation of state based approach.
Using Co-Solvents to Provide Gradients and Improve Oil Recovery during Chemical Flooding in a Light Oil Reservoir
Authors: Dwarakanath V. , Chaturvedi T. , Jackson A. C. , Malik T. , Siregar A. , Zhao P.
Published: April 2008

The effect of co-solvent on phase behavior was evaluated and an optimal surfactant/co-solvent formulation was selected based upon a combination of simulations and laboratory experiments. The co-solvent altered phase behavior, thereby necessitating a different approach for inducing effective salinity gradients. We present an approach where the hydrophilic nature of the co-solvent is used to maintain effective salinity gradients to optimize surfactant behavior but more importantly mitigate viscous microemulsions and reduce surfactant retention. By using a combination of laboratory experiments and simulations to match co-solvent behavior in UTCHEM, Using an understanding into co-solvent partitioning was developed such that the optimal conditions of ultra-low interfacial tensions are maintained for a longer duration during chemical flooding. We demonstrated that by adding the appropriate co-solvent and the correct amount of electrolyte in the chase solutions, we could maintain Winsor type III conditions for extended durations even with a small surfactant slug. The optimal co-solvent/electrolyte gradient recovered more than 90% of the residual oil in laboratory corefloods. The result illustrate the importance of characterizing the effect of co-solvent on surfactant phase behavior and the need for numerical modeling to optimize chemical flood design when co-solvent is used.
The Potential for Additional Carbon Dioxide Flooding Projects in the United States
Authors: Mohan Hitesh , Carolus Marshall , Biglarbigi Khosrow
Published: April 2008

In recent years, sustained increases in crude oil prices and continued decline in domestic conventional production have renewed national interest in Carbon Dioxide Enhanced Oil Recovery (CO2 EOR). Growing concern about climate change and greenhouse gases has increased interest in carbon capture and sequestration. CO2 EOR provides a value added opportunity to increase crude oil production and sequester substantial volumes of industrial CO2.

An analysis was conducted to determine the incremental domestic production which could be realized if industrially produced CO2 is made available for EOR. The challenges are the volumes of CO2 which can be made available, the infrastructure requirements, and the prices at which the CO2 can be made available. 1,673 potential CO2 EOR candidate reservoirs (with an estimated technical recovery of about 20 Billion barrels) were analyzed. These reservoirs were timed and developed subject to the availability of CO2 at a price economical to the EOR producer. To determine CO2 availability, a wide array of natural and industrial CO2 sources was mapped along with candidate EOR reservoirs. Potential pipeline routes were developed to determine the volume of CO2 available from each industrial source, and to calculate the tariff required to transport it to potential fields. Where volumes from concentrated sources like ethanol or hydrogen plants were insufficient for a project, several such sources were linked through gathering lines and connected to potential fields through a trunk line. The price of industrial CO2 delivered to the producer includes the capture cost and regional pipeline tariff. This price was used to determine the economics and development of EOR projects.

The analysis indicates that by increasing availability of CO2 through wide-spread capture and sale of CO2 from industrial sources, and with oil prices between $45–$60/Bbl, approximately 1.2 Million barrels per day (MMBbl/d) of incremental oil production can be realized while sequestering ∼300 Million tons per day (Mtn/d) of CO2.
LoSal™ Enhanced Oil Recovery: Evidence of Enhanced Oil Recovery at the Reservoir Scale
Authors: Lager A. , Webb K. J. , Collins I. R. , Richmond D. M.
Published: April 2008

For over 10 years research has been carried out on the impact of low salinity waterflooding on oil recovery. Data derived from corefloods, single well tests, and log-inject-log tests have shown that injecting low salinity water into an oil reservoir should result in a substantial increase in oil recovery in many cases. The results varied from 2 to 40% increases in waterflood efficiency depending upon the reservoir and composition of the brine.

In 2005, a hydraulic unit was converted to inject low salinity brine into an Alaskan reservoir, by switching a single injection pad to low salinity water from high salinity produced water. An injector well and 2 close production wells were selected within a reasonably well constrained area. A surveillance programme was devised which included capturing produced water samples at regular intervals for ion analysis and the capturing of production data.

Detailed analysis of the production data, and the chemical composition of the produced water, demonstrated an increase in oil production and provided direct field evidence of the effectiveness of LoSal™ at inter-well scales. Additionally, the response of the reservoir to low salinity water injection was confirmed by single well chemical tracer test.

In parallel, laboratory studies have led to mechanistic understanding of LoSal™ in terms of multiple-component ionic exchange (MIE) between adsorbed crude oil components, cations in the insitu brine and clay mineral surfaces. The results clearly show that the enhanced oil production and associated water chemistry response was consistent with the MIE mechanism proposed.

The oil production data have been modeled using an in-house developed modification to Landmark's VIP™ reservoir simulation package. An excellent match for the timing of the oil response was obtained which provides a good basis for predicting the result for large scale application of LoSal™ flooding.
Effective Use of Heterogeneity Measures in the Evaluation of a Mature CO2 Flood
Authors: Senocak Didem , Pennell Stephen P. , Gibson Charles E. , Hughes Richard G.
Published: April 2008

Heterogeneity measures have a long history in the oil and gas industry but have fallen somewhat out of favor in recent years with the advent of more statistically robust characterization tools. Theoretically-based correlations between heterogeneity measures and recoveries at various stages of a waterflood appear to be one of the primary tools in the design and early evaluation of floods when they were initially proposed. Field-wide reports of the heterogeneity measures and their relationship to enhanced recovery response were also reported in the literature, but it is unclear as to whether general correlations were developed or widely used as they were for waterflooding.

In this work we evaluate several heterogeneity measures in terms of recovery efficiency and utilization rate in a mature CO2 flood. Core studies available from 41% of the wells in the Little Creek Field, Mississippi were used to compute various heterogeneity measures and the resulting values were correlated with pattern-by-pattern and development area recoveries and CO2 utilization rates at various times over the life of the flood. Weak correlation trends were found for most of the measures when recoveries were evaluated. Slightly stronger correlations were found with utilization rates.

Much more significantly, mapping of the well-by-well heterogeneity measures appear to show geological trends better than traditional maps of the basic parameters that make up the measures. These geological trends were then successfully used to adjust rock-types and guide geostatistical modeling of permeability and porosity when performing reservoir modeling and history matching.
Integrated Clustering/Geostatistical/Evolutionary Strategies Approach for 3D Reservoir Characterization and Assisted History-Matching in a Complex Carbonate Reservoir, SACROC Unit, Permian Basin
Authors: Gonzalez R. , Schepers K. , Reeves S. R. , Eslinger E. , Back T.
Published: April 2008

An integrated methodology combining clustering analysis techniques, geostatistical methods and evolutionary strategy technologies was developed and applied to an area in the SACROC Unit (Permian basin). Clustering methods were applied to well logs and core data with high vertical resolution for many wells to predict porosity, permeability and rock type. Geostatistics was applied to extend the characterization into the inter-well area. Evolutionary strategies were used to refine the characterization to match historical production performance.

The complete approach was tested on an area within the SACROC Unit, acknowledged as a highly heterogeneous carbonate reservoir with complex production history. Three cored wells provided porosity and permeability measurements on a foot-by-foot basis. These measurements coupled with well logs were used to predict porosity, permeability and flow units. Twenty two wells in the study area having foot-by-foot profiles of porosity and permeability were considered sufficient to characterize porosity and permeability in three dimensions. Geostatistical methods were then used to build porosity and permeability models.

As a validation of the characterization procedure, evolutionary strategy jointly coupled with a black oil reservoir model was used to history match production performance of a 0.5 mi2 area. The 65,340 grid-block model had over 50 years of production. Thirteen (13) input parameters were varied during the history match. Among them, a multiplying factor was applied to the permeability realization to account for upscaling effects, varying permeability values without modifying geological heterogeneities identified during the characterization process. No adjustment to porosity characterization was permitted.

A very good history match of individual production was achieved for the center wells of the area, and a good match was also obtained for outer wells production and reservoir pressure where boundary effects existed. This validates the new integrated clustering/geostatistical/evolutionary-strategy approach in this highly heterogeneous carbonate reservoir.
Effect of Heterogeneous Capillary Pressure on Buoyancy-Driven CO2 Migration
Authors: Saadatpoor Ehsan , Bryant Steven L. , Sepehrnoori Kamy
Published: April 2008

We examine buoyancy-driven multiphase flow when the less dense phase is placed below the other phase in a heterogeneous domain. After generating geostatistical realizations of permeability, we apply the Leverett.J-function so that each grid block has a drainage curve (Pc vs Sw) physically consistent with its permeability. The behavior of the displacement front depends strongly on the correlation structure of the heterogeneity and upon the magnitude of the mean entry pressure. This behavior is of particular interest for assessing the degree of immobilization of anthropogenic CO2 injected into an aquifer.

In a relatively homogeneous domain, capillarity is a second-order effect. It damps the instability of the rising CO2 front and smooths the shape of the plume. As the heterogeneity of the aquifer increases, capillarity begins to dominate buoyancy. Regions with smaller permeability that would readily conduct single-phase flow can completely block rising CO2, simply because the capillary entry pressure in these regions is somewhat larger than in neighboring regions. These local capillary barriers prevent CO2 from rising and cause it to move laterally. The disruption can be so extreme that above-residual saturations of CO2 become trapped below these barriers. These local accumulations respond differently when the top seal of the aquifer is breached. Thus we distinguish them as a new mode of CO2 trapping, dubbed "capillary trapping." Overall, in some regions the CO2 follows preferential flow paths determined by the spatial correlation of permeability, while in others capillarity determines the flow path. Though the displacement front is much less uniform, the extent of dissolution trapping remains significant.
Evaluation of Manson Lease Oil Field for Improved Oil Recovery Process
Authors: Tsau J. S. , Vaca Bustamante V. , Green D. W. , Barnett B. , Dale J. L.
Published: April 2008

Typical oil fields in eastern Kansas area are shallow, low temperature reservoirs. Historically, waterflooding has commonly been applied as a secondary oil recovery method. In some cases, polymer flooding has been used to optimize the recovery of waterflooding. A polymer augmented waterflood was applied at the Manson lease, part of the West Savonburg oil field, starting in 2000. The lease had a very poor oil recovery and a study was initiated to evaluate reservoir performance in an attempt to understand the cause of the poor recovery. The evaluation processes included development of a geological model, core analysis and reservoir simulation. Poor sweep efficiency was found to result from water channeling thought to be caused by fracturing wells unintentionally during the polymer injection. As a result of the study, infill drilling and modification of field injection were implemented to continue the waterflood. In addition, the feasibility of CO2 application in this low temperature, low pressure reservoir was explored. Oil swelling factors and minimum miscibility pressure were measured using a vapor-liquid equilibrium view cell and a slim-tube apparatus, respectively. At the current reservoir conditions, the displacement of CO2 was found to be an immiscible process and, in general, not an economically viable process.
Investigation into the Processes Responsible for Heavy Oil Recovery by Alkali-Surfactant Flooding
Authors: Bryan J. , Mai A. , Kantzas A.
Published: April 2008

This paper describes a suite of alkali-surfactant (AS) floods that were performed in systems containing viscous heavy oil (11,500 mPas). The study investigates how AS injection can be used to generate oil and water emulsions, which can in turn lead to improved sweep efficiencies and oil recovery. Data is obtained from core flooding, with in-situ saturation measurements made using low field NMR. This work is applicable to the many heavy oil reservoirs in countries like Canada and Venezuela that contain viscous oil that still has some limited mobility under reservoir conditions. In previous studies, improved oil recovery compared to waterflooding was observed. This work provides additional information that can be used to better understand how chemical injection can lead to oil recovery.

The core floods in this study indicate that emulsification is most efficient when used to block pre-formed water channels and improve the sweep efficiency of the flood. Both O/W and W/O emulsions may form in the same system, even under controlled salinity conditions. The re-distribution of water from the flooded channels into emulsified droplets in the oil is at least partially responsible for the pressure increase seen in these systems. W/O emulsification is accompanied by wettability alteration, as evidenced by the NMR spectra obtained. After the chemical flood is completed, it may be possible to restore the original water wet condition of the rock, which can provide potential for future non-thermal improved oil recovery.
Investigation of Diffusion Coefficients of Heavy Oil and Hydrocarbon Solvent Systems in Porous Media
Authors: Luo H. , Kantzas A.
Published: April 2008

Solvents can be injected to dilute viscous heavy oil or bitumen and improve the recovery of the vast reserves of heavy oil and bitumen in Canada. In an evolution of the SAGD and VAPEX processes, some new schemes that use solvent and steam appeared to offer a more economical and environmentally sound alternative to extract heavy oil and bitumen compared to SAGD alone. Mass transfer rates determine whether these solvent-assisted processes are feasible for heavy oil and bitumen recovery. The solvent-bitumen diffusion coefficient is a basic parameter needed. According to previous literature, the effective diffusion coefficient in porous media is much smaller than the true diffusion coefficient in bulk fluids. However, good-quality data from diffusion experiments of heavy oil and hydrocarbon solvent systems for effective diffusion coefficients determination in porous media is still scarce. This paper presents diffusion experiments of liquid solvent in heavy oil saturated sand using X-ray Computer Assisted Tomography (CAT), and determines the effective diffusion coefficients based on an updated approach, which considers porosity variation of porous media and volume changes on mixing. In addition, the relationship between the effective diffusion coefficient of solvent in oil saturated sand pack and the true diffusion coefficient in bulk fluids is investigated.
Case Study on Preformed Particle Gel for In-Depth Fluid Diversion
Authors: Bai Baojun , Huang Fusheng , Liu Yuzhang , Seright R. S. , Wang Yefei
Published: April 2008

The paper describes preformed particle gel (PPG) treatments for in-depth fluid diversion in four injection wells located in the north of Lamadian, Daqing oilfield, China. Lamadian is sandstone oilfield with thick net zones. The selected four injectors have 46 connected producers with average water cut of 95.4% before treatment. The paper reports the detailed information for the four well treatments, including well candidate selection criteria, PPG treatment optimization, real-time monitoring result during PPG injection and reservoir performance after treatment. In addition, a discussion is made to analyze why so large amount of large particles can be injected into the reservoir. Large volume of PPG suspension with concentrations of 2,000–2,500 mg/L and particle sizes of 0.06–3.0 mm was injected into each well and it took about 4 months to finish each injection. The injection volume ranges from 11,458 to 17,625 m3 per well with a total of 56,269 m3 of PPG suspension (295,680 lbs of dried PPG) for the four wells. During PPG injection, the increase of the wellhead pressure was quite stable and no PPG was produced from adjacent producers. Recorded real-time monitoring Data about injection pressure and rate, PPG particle size change during PPG injection provide invaluable information to analysis the possibility of fracture/channel in the reservoir. The treatments resulted in an oil increase of 34.8 t/d and average water cut decrease of 0.94% within 10 months after treatments.