bluuebunny/crossref_metadata_2025 huggingface dataset:
Development of Improved Hydrocarbon Recovery Screening Methodologies
Authors: Dickson Jasper L. , Leahy-Dios Alana , Wylie Philip L.
Published: July 2010

This paper describes a novel improved hydrocarbon recovery (IHR) screening methodology capable of (1) screening and prioritizing a large number of reservoirs for various IHR processes and (2) generating preliminary flowstreams through generic sector modeling and proxy simulation. This methodology enables quick screening for a variety of EOR techniques using reservoir rock/fluid properties and technical/economic screening criteria, and quantitatively ranks the EOR options. It also provides the means to complete a first-pass estimate of reservoir performance by applying case-specific performance curves to run facility level simulations. It has been thoroughly tested for various fields where different EOR strategies were or are being implemented, and the results are in good agreement with published data. This methodology helps identify potential IHR opportunities, enabling operators to quickly test the validity and relative merits of IHR for any field or reservoir.
Modification of Capacitance-Resistive Model for Estimating Waterflood Performance
Authors: Chen Huan , Zhang Zhihong , Sun Wenjie , Li Kewen
Published: July 2010

One of the important parameters in capacitance-resistive model (CRM) for the prediction of production performance is fij, representing the fraction of injection rate of injector i flowing toward producer j. However fij was usually assigned to unity when a reservoir is represented by a single producer and a single injector as a tank. We found that this might not be true in many cases. In this study, the above assumption of unity fij was relaxed in the case of lump reservoir model (tank model). Another problem in applying CRM is the poor accuracy of the match and prediction of oil production. In this study we modified the CRM for matching and predicting oil production with greater accuracy than the existing fractional flow model. Production data from chosen oil reservoirs were analyzed using both existing and modified approaches and the results were compared. The results showed that the modified CRM approach could fit the production performance better than the existing CRM in many cases. This study demonstrated that the assumption of unity fij could be removed in the case of lump reservoir model. The physical significance behind this was proposed and explained. The results and analysis demonstrated that the accuracy of the modified oil production model was significantly greater than the existing fractional flow model in many cases.
Selective Polymer Treatments Improve Oil Recovery in Five Mature Southern Oklahoma Waterfloods
Authors: Portwood J. T. , Lackey Scott H. , Abel Scott W.
Published: July 2010

The Healdton Field was discovered in 1913 and is located in Carter County, Oklahoma. A total of 8 units covering 8,160 acres were formed in the 1960's to waterflood a thick sequence of shallow sandstones that were deposited in an area that is 10 miles long and 3 miles wide. Today, 317,000 BW are injected into 350 wells to produce 2,200 BOPD + 324,000 BWPD from 800 wells. There are 2 units in the area that are not being waterflooded. Historically, injection profile logs and high water-cuts at producers have indicated that injected fluids have never been evenly distributed throughout the sands due to a large variation in permeability. In spite of using mechanical zone isolation techniques to improve vertical sweep, significant volumes of mobile oil trapped in lower permeability rock have been by-passed. The remaining mobile oil could not be economically recovered in a reasonable amount of time unless the injected fluids could be redistributed more uniformly throughout the sands in both the areal and vertical planes.

Since March 2006, a total of 56 water injection wells in 5 of the waterflood units have been treated with relatively large volumes of cross-linked polymer gel to improve the distribution of injection water, provide for better volumetric sweep efficiency, and higher oil recovery. Bullhead treatments blended in formation brine were custom designed for each candidate injection well. Novel treatment strategies had to be developed so that large polymer volumes could be injected in a field where well spacing is "tight" (2.5 – 5.0 acres) and where polymer breakthrough is possible. To date, a total of about 745,000 barrels of polymer gel have been injected.

The project has resulted in sharply higher oil production, lower WOR, and higher oil-cut percentage. Nearly 170,000 barrels of incremental oil have been recovered during the first 3.8 years of the project, and it is estimated that ultimate incremental recovery will approach at least 2.3 MMBO. Further, it is estimated that the treatments have added at least 10 years to the economic life of these 5 units at current oil prices. Although overall project economics have been very favorable, the lessons learned from this project will be used to more effectively apply the technology to other areas in this field and to other sandstone waterfloods in general.
General Strategy for Stability Testing and Phase-split Calculations in Two and Three Phases
Authors: Li Z. , Firoozabadi A.
Published: July 2010

Efficient and robust phase equilibrium computations have become a pre-requisite for successful large scale compositional reservoir simulations. When the initial estimate of equilibrium ratios is not available from previous simulation time step, the ideal strategy for the phase-split calculation is the use of stability testing. We present a general strategy for two-and three-phase split calculations based on reliable stability testing where we apply the quasi-Newton method with superlinear convergence rate. The Wilson correlation and new correlations are combined to provide the initial estimate of equilibrium ratios. In the phase-split calculation, the successive substitution iteration (SSI), General-Dominant-Eigenvalue (GDE), and Newton methods are combined. The SSI is only first-order and is generally used to provide the initial guess for the Newton method. The GDE update is adopted to accelerate the SSI. The Newton method has quadratic convergence rate and can locate the solution within a few iteration steps when the initial guess is close enough to the solution. Powerful features of the strategy are extensively tested by calculating the complicated phase envelops of four hydrocarbon fluids mixed with CO2 in single-, two-, and three-phase regions.
Improving Steam-Assisted Gravity Drainage Using Mobility Control Foams: Foam Assisted-SAGD (FA-SAGD)
Authors: Chen Q. , Gerritsen M. G. , Kovscek A. R.
Published: July 2010

Steam-assisted gravity drainage (SAGD) is a promising approach for recovering heavy and viscous oil. The success of SAGD relies on two key operations: uniform formation of the steam chamber along the full length of the injector, and effective control of steam breakthrough by sustaining a liquid level between the injector and producer (i.e. a steam trap). Intrinsic permeability heterogeneities typically lead to a partially-developed steam chamber and potentially low sweep efficiency that results in reduced oil production. The injectivity variability along the well also complicates the control of steam breakthrough. To overcome these difficulties, we propose the use of foamed steam. The feasibility of foam-assisted SAGD (FA-SAGD) is demonstrated numerically with a local-equilibrium foam simulator incorporating the physical mechanisms of foam generation, destruction, and transport. The model was validated previously. Simulation results show that strong foam is generated and accumulates in the interwell region. The presence of foamed steam helps to control steam breakthrough and yields better recovery performance per barrel of steam injected than conventional SAGD. Live steam production in simulations is reduced by a factor of 5. Consequently, cumulative oil production is increased by about 30% in comparison to cases without foam. Sensitivity analysis of the parameters describing foam indicate that the process is robust.
An Integrated Workflow for Chemical EOR Pilot Design
Authors: Moreau P. , Morvan M. , Rivoal P. , Bazin B. , Douarche F. , Argillier J.-F. , Tabary R.
Published: July 2010

After primary and secondary production of oil from a petroleum reservoir, more than half of the oil is often left in place. In order to improve the process displacement efficiency – so that one can recover some of this remaining capillary-trapped or water-by-passed oil –, it is necessary to apply enhanced oil recovery (EOR) techniques such as surfactant flooding, either Surfactant (S), Surfactant-Polymer (SP) or Alkaline-Surfactant-Polymer (ASP).

This paper describes a complete workflow for optimizing S, SP or ASP processes for chemical EOR. The workflow consists in successive steps: reservoir fluid and rock characterizations, formulation screening, core flood validation and simulation including sensitivity studies.

Formulation design is performed through a validated High Throughput Screening (HTS) methodology using a robotic platform combined with microfluidic tools. Objective of the formulation platform is to provide a robust formulation adapted to the variability of the reservoir conditions (temperature and salinity windows, oil composition). Data on brine compatibility, oil solubilization ratio and water-oil interfacial tension (IFT) are systematically provided. Adsorption measurements are conducted for the selection of the best formulations. Core flood experiments are performed to validate performances of selected chemical formulation(s) and define simulation input data. IFT measurements, adsorption data, capillary desaturation curves, and diphasic water-oil relative permeabilities are further used as input for simulations. A chemical EOR simulator (SaripCH software), specifically designed for ASP processes design, has been developed. After the lab study, pilot design is the next step towards the application of the S, SP or ASP process in the field. SaripCH simulator is used to evaluate the performances of the process at the reservoir scale.
Water Alternating High Pressure Air Injection
Authors: van Batenburg D. W. , de Zwart A. H. , Doush M.
Published: July 2010

High Pressure Air Injection (HPAI) is a potentially attractive enhanced recovery method for deep, high-pressure light oil reservoirs. The clear advantage of air over other injectants, like hydrocarbon gas, carbon dioxide, nitrogen, or flue gas is its availability at any location. Although, the process has successfully been applied in the Williston Basin for more than two decades, the potential risks associated with the presence of oxygen in air are a significant hurdle for implementation in other locations.

Thermal simulations that include combustion are required to quantify the incremental oil, the oxygen consumption and resulting oxygen distribution from the application of HPAI in a given field. Once such a simulation model is available, it can be used to optimize the injection strategy: strategies that have a good incremental recovery while reducing the amount of gas injected are key to a successful project. The injection rate is bounded by a technical lower limit and an economic upper limit: there is a minimum rate required to maintain the combustion and higher rates require larger compressors that are more expensive.

This paper focuses on the optimization of the injection strategy for HPAI in a 3D model with realistic geological features. Numerical simulations with a thermal model that includes combustion were conducted for continuous versus alternating air injection. A critical assumption for alternating air injection is that the remaining oil spontaneously re-ignites.

This study shows that water alternating air injection has a great potential to improve HPAI projects: project life can be extended and incremental recovery is improved when compared with continuous air injection. In addition, the variation in distribution of oxygen between different cycles is presented. This also illustrates that the numerical model can be used as an oxygen management tool. The effects of alternating air injection are comparable to the effects of alternating gas injection: the saturation in the swept areas changes due to the alternating (re-) invasion of gas, oil and water.

This paper illustrates that modeling oxygen consumption is essential for the evaluation of potential risks and optimization of the HPAI process.
Enhanced Oil Recovery of Viscous Oil by Injection of Water-in-Oil Emulsion Made with Used Engine Oil
Authors: Fu Xuebing , Mamora Daulat
Published: July 2010

Water-in-Oil (W/O) emulsion has been proven to be an effective driving fluid for viscous oil (>100cp) recovery. However, finding an oil that is cheap and easily available to make the emulsion is a problem. In a recent patent, crude heavy oil was used to make W/O emulsions to recover the same oil in a sand pack flooding experiment, with almost 100% recovery achieved. This crude oil emulsion was stabilized by oleophilic nanoparticles without any surfactant required. However, its viscosity was unfavorably high: a 60% water content W/O emulsion is over 10 times more viscous than the original oil—far beyond the required level for mobility control, resulting in poor injectivity.

This paper introduces a new idea of making W/O emulsion with a very common material— used engine oil. Over a billion gallons of engine oil are used in the US every year, and it has been a major contributor to pollution due to improper disposal. However this used engine oil could be a very good candidate to make W/O emulsions. First of all, the soot (organic carbons) from the breaking down of the engine oil provides perfect solid particles to stabilize the emulsion; secondly, its moderate viscosity permits an optimal viscosity to be achieved when making an emulsion. The detergent in the original engine oil and the acidity caused by oxidation of the oil may also help stabilize the W/O emulsions.

In this research different types of used engine oil (mineral based, synthetic) were tested to make W/O emulsions simply by blending in brine. A series of stable emulsions were obtained with varied water contents from 40~70%. Viscosities of these emulsions were measured, ranging from 102~104 cp at low shear rates and ambient temperature. As a potential driving fluid, used engine oil emulsions can be targeted at various heavy oil reservoirs because of the wide viscosity range.
Preformed Particle Gel Transport through Open Fractures and its Effect on Water Flow
Authors: Zhang Hao , Bai Baojun
Published: July 2010

Transparent fracture models were constructed to visually track swollen preformed particle gel (PPG) propagation through open fractures and water flow through PPG placed in fractures. It was observed that PPG propagated like a piston along a fracture during PPG injection and a gel pack was formed in the fracture after gel placement and water broke through the particle gel pack to create several water channels to discharge water from the outlet during water injection after PPG placement. The factors that influence PPG injectivity and plugging efficiency have been investigated. Results show that PPG injectivity increases with fracture width and flow rate and decreases with brine concentration on which PPG swollen ratio is dependent. PPG can reduce the permeability of different width fracture to the same level. Full factorial experimental design was performed to rank the influence of injection rate, fracture width, and PPG swelling ratio on the response of pressure, resistance factor and injectivity.
The Influence of Salt Concentration in Injected Water on Low Frequency Electrical-Heating Assisted Bitumen Recovery
Authors: Bogdanov I. I. , Torres J. A. , Akhlaghi H. A. , Kamp A. M.
Published: July 2010

Steam injection is often not a good alternative for oil recovery from shallow bitumen reservoirs; for instance, the thin cap-rock creates the danger of steam breakthrough. For deeper reservoirs the heat losses from injection well may be prohibitive. A technology that may be better suited is oil recovery aided by electrical low frequency heating of the reservoir. This technology, well known for environmental remedial applications, has been recently field-tried, yielding promising results. The process uses electrical conductivity of connate water to propagate an alternating current between electrodes, inducing the Joule heating of the reservoir. An associated problem is the appearance of hot spots around the electrodes that may be relieved by water circulation. However, the water circulation may have a significant effect on the heating process because the electrical conductivity of the circulated water depends on its salt content.

In order to find out the influence of salt concentration on process efficiency we have studied the process of salt water recirculation around an electrode using numerical simulation. The physical properties and operational data for Athabasca bitumen have been collected from the literature. The model built with CMG STARS™ simulator and tested first with available analytical solutions, has been validated and the proper choice of the underlying grid and numerical tuning parameters has been verified. The process was also studied at field scale for a common pattern of electrodes and production wells. The salt turned out to penetrate into the reservoir, far beyond the major water circulation zone around the electrodes. This process increases the electrical conductivity in a large region between electrodes, which improves the heating of the reservoir. The single-electrode simulation studies using the different tools yielded similar results for a simple problem. More complex (and more realistic) field-scale simulations show that adding salt enhances finally the oil production. In practice an upper concentration limit is given by corrosion problems at the electrodes.

The reservoir simulation of bitumen recovery assisted by low-frequency heating is a challenging multiphysics problem. The understanding of the influence of salt concentration on the circulated water provided by this work is an important key in process design considerations.
Inaccessible Pore Volume of Associative Polymer Floods
Authors: Pancharoen M. , Thiele M. R. , Kovscek A. R.
Published: July 2010

Approximately half of current oil production is from waterfloods where a major concern is mobility control of the injected phase. Addition of polymer to the injection water decreases the mobility ratio leading to greater flood efficiency, especially for recovery of viscous oil. Of the various EOR polymer formulations, newly developed associative, water-soluble polymers show special promise. We investigate, experimentally and numerically, the inaccessible pore volume (IPV), permeability reduction (Rk), and interfacial tension characteristics of 3 different molecular weight associative polymers and, for reference, a conventional hydrolyzed polyacrylimide. Previous studies of these same associative polymers revealed good secondary and tertiary oil recovery efficiency for displacement of a viscous 140 cP oil. To our knowledge, this is the first study to observe and report IPV – Rk properties of these associative polymer solutions. New experiments were conducted by injecting polymer solutions through a roughly 12 Darcy sandpack and measuring the separation between effluent concentration profiles of the polymer and the salt used as the tracer. Results are interpreted from the effluent profiles using an analytical superposition model as well as a conventional finite difference formulation. The associative polymers yield moderate to large IPV (20 to 40%) and mild Rk (1.1 to 1.5) that increases with molecular weight. Brine salinity reduces both IPV and permeability reduction. Differences between the classical interpretation, the analytical interpretation, and the numerical implementation of IPV are discussed as is the adequacy of the conventional IPV-Rk description of the mobility control of polymer.
A New Process for Manufacturing and Stabilizing High-Performance EOR Surfactants at Low Cost for High-Temperature, High-Salinity Oil Reservoirs
Authors: Adkins Stephanie , Liyanage Pathma J. , Pinnawala Arachchilage Gayani W. , Mudiyanselage Thilini , Weerasooriya Upali , Pope Gary A.
Published: July 2010

An alcohol dimerization process known as the Guerbet reaction is used to create large alcohol structures for the production of the corresponding alkoxy sulfate surfactants. In the alcohol industry, Guerbet (dimer) alcohols are considered the "gold" standard for large, branched alcohols. These Guerbet alcohols tend to be more expensive than other alcohols when produced in high purity for various industrial applications. The high cost is mainly due to driving the reaction to completion and/or stripping-off of the unreacted monomer alcohol to produce high purity. However, inexpensive Guerbet alcohols (GA) can be prepared by aiming for less than quantitative conversion during the alcohol dimerization process. The resultant blend of 85-95% GA and 5-15% monomer alcohol is subsequently used in the alkoxylation process to add propylene oxide and/or ethylene oxide, followed by sulfation. Through the use of this new Guerbet process, these surfactants can be manufactured at low cost when made as sulfates as opposed to sulfonates. For example, a C32 GA can be produced from a C16 alcohol. These and other sulfate surfactants can be stabilized at high temperature with alkali. This is a surprising discovery that greatly increases the availability of low-cost, high performance surfactants for high temperature reservoirs.
A Microbial Enhanced Oil Recovery Field Pilot in a Brazilian Onshore Oilfield
Authors: Reksidler Rodrigo , Torres Volpon Antonia Garcia , Barbosa Luiz Cesar , Brasileiro Cláudio Guilherme , Nicolau Heitor Cesar , de Calasans José Augusto
Published: July 2010

An onshore oilfield, located in the northeast of Brazil, is being submitted to a microbial EOR method to reduce problems associated with high permeability zones.

Ten water injection wells were selected to the field trial. The method consists in the dosage of nutrients and an electron acceptor in the injection water, in order to stimulate microorganisms to produce biomass and biopolymer to plug high permeability zones.

Pressure, flow rate and injectivity profile are being monitored. The results demonstrated that the process is effective. Five wells indicated the plugging of the high permeability zone, due the pressure increase and flow rate decrease. Only three of these wells were evaluated by injectivity profile, and two of them presented improvements on the vertical sweep efficiency.
Prediction of Three-Phase Gravity Drainage from Two-Phase Capillary Pressure Curves
Authors: Mirzaei Mohammad , DiCarlo David , Ashouripashaki Mandana , Dehghanpour Hasan , Aminzadeh Behdad
Published: July 2010

Gravity drainage of oil with gas and the migration of non-aqueous phase liquid (NAPL) spills in the unsaturated zone are two of the most common processes where the three-phase capillary/gravity equilibrium plays an important role. Although three-phase gravity drainage is highly effective for water-wet media, predicting the profiles and ultimate recovery for mixed and oil-wet media is essential as most reservoirs have a mixed-wet nature.

The three-phase capillary/gravity equilibrium is different from the two-phase equilibrium, similar to the difference between two-phase and three-phase relative permeability. For water-wet media and spreading oils, the profiles can be predicted from the two-phase pressure-saturation curves. However, the predictions are more complicated for mixed-wet media because of the difference in fluid configuration in pores. We propose a simple method for predicting the three-phase equilibrium saturation profile and test our method using the experimental data. The experimental method used in this study includes performing a series of two-phase capillary pressure measurements and three- phase gravity drainage tests in columns containing fractionally wet sands. The two-phase experiments are compared to experimentally measured three-phase drainage saturation profiles of the same wettability. The bottom of the column is supported by an aquifer such that no oil is produced.

The results show that the transition between single phase, two-phase and three-phase zones can be accurately predicted using the two-phase drainage capillary pressures. However, the proposed method is unable to predict the final residual saturation, especially in columns with faction of oil-wet sand exceeding 50%.

Because two-phase data for reservoir cores are more accessible than three-phase data, the results of this study are valuable for predicting the saturation distribution in a three- phase gravity drainage process in mixed-wet media, particularly in reservoirs with a wettability gradient. The results of the study may also be applicable to study of CO2 sequestration in aquifers.
Simulation of Expanding Solvent – Steam Assisted Gravity Drainage in a Field Case Study of a Bitumen Oil Reservoir
Authors: Akinboyewa John , Das Swapan K. , Wu Yu-Shu , Kazemi Hossein
Published: July 2010

With the increasing demand for energy around the world, more attention is directed to heavy oil and bitumen reservoirs for energy supply. Currently, these high viscosity heavy oil resources are produced primarily by steam. For instance, steam assisted gravity drainage (SAGD) is used widely for the exploitation of bitumen from relatively shallow reservoirs in Alberta, Canada. However, to increase the efficiency of SAGD operations and to improve economics, it has been proposed to add solvent to the injected steam.

With solvent injection, there is an increase in the production rate and a reduction in the required injected steam, resulting in a lower steam-bitumen ratio (SBR). Higher concentrations of injected solvent show additional enhancement in oil production rate including some of the solvents. Although simulation results show that the rates of solvent recovery vary depending on the concentration and the nature of solvent used. For optimal results, injection strategy needs to be adjusted depending on the geological conditions, solvent characteristics and reservoir properties.

The study presented in paper was motivated by observing promising results of a field test with solvent injection in a SAGD bitumen project. The study began with a compositional thermal simulator to quantify the benefits of solvent addition to the SAGD process (referred to as ES-SAGD) to produce bitumen more efficiently with lower energy requirements. A secondary objective was to determine the optimal and more cost-effective operational protocol for such solvent-steam injection projects.

The paper presents (1) the methodology used to model the ES-SAGD enhanced oil recovery process, and (2) reports the field and modeling results of the application of the ES-SAGD process to an oil sand project in Alberta, Canada.
Development of a Viscoelastic Property Database for EOR Polymers
Authors: Kim Do Hoon , Lee Seungjun , Ahn Chong Hyun , Huh Chun , Pope Gary A.
Published: July 2010

Partially hydrolyzed polyacrylamide (HPAM) and related polymers are widely used as mobility control agents in all chemical EOR applications, and an accurate characterization of their apparent viscosity in the reservoir rock is crucial for design and performance evaluation of these processes. Their apparent viscosity in porous media generally decreases as flow velocity increases; however, beyond a certain critical velocity, the apparent viscosity sharply increases, showing shear-thickening behavior. A procedure to predict both the shear-thinning and shear-thickening apparent viscosities, from the rheometer-measured shear and oscillatory viscosities, has been developed earlier and validated with corefloods (Delshad et al., 2008). In addition to the shear viscosity database developed earlier (Lee et al., 2009), a database of the oscillatory viscosities of the EOR polymers was therefore developed for wide ranges of polymer concentration, NaCl salinity and calcium content, and temperature. The generalized Maxwell model (GMM) is employed to estimate the relaxation time of the polymer solution, by making non-linear fitting of the measured G' and G" data to GMM. Empirical correlations were developed to predict the relaxation time, which is subsequently used to quantify the shear-thickening portion of the apparent polymer viscosity under different process conditions. The apparent viscosity estimated matches reasonably with the available coreflood data.
Low-Cost, High-Performance Chemicals for Enhanced Oil Recovery
Authors: Yang Hyuntae , Britton Christopher , Liyanage Pathma J. , Solairaj Sriram , Kim Do Hoon , Nguyen Quoc , Weerasooriya Upali , Pope Gary A.
Published: July 2010

The ability to select low-cost, high-performance surfactants for a wide range of crude oils under a wide range of reservoir conditions has improved dramatically in recent years. We have developed surfactant formulations (surfactant, co-surfactant, co-solvent, alkali, polymer, electrolyte) using a refined phase behavior approach. Such formulations nearly always result in more than 90% oil recovery in both outcrop and reservoir cores when good surfactants with good mobility control are used. Chemical flood residual oil saturations are typically less than 0.04 and surfactant retention between 0.01 and 0.1 mg/g with these formulations using as little as 0.2% surfactant concentration and 30% pore volume ASP slugs. We describe some of the advances that have improved the performance, reduced the cost, increased the robustness, and extended the range of reservoir conditions for these formulations. There are thousands of possible combinations of the chemicals that could be tested for each oil and each chemical combination requires many observations over a long time period at reservoir temperature for proper evaluation, so it would take too long, cost too much and in many cases not even be feasible to test all combinations. In practice we use our scientific understanding of how to match up the surfactant/co-surfactant/co-solvent characteristics with the oil characteristics, temperature, salinity, hardness and so forth. We have synthesized and tested new surfactants with much larger hydrophobes and more branching than previously available. We have tested new classes of co-solvents and co-surfactants with superior performance. These new developments have enabled us to develop good formulations for both oils that react with alkali to make soap and oils that do not. We have significantly lowered the chemical cost needed for waxy crudes with very high equivalent alkane carbon numbers. We have good results for oils with API gravities as low as 17, high temperature, high salinity, and high hardness brines. Many of these developments are synergistic and taken together represent a breakthrough in reducing the cost of chemical flooding and thus its commercial potential in both sandstone and carbonate reservoirs.
Bayesian Decision Networks for Optimal Placement of Horizontal Wells
Authors: Rajaieyamchee M. A. , Bratvold R. B. , Badreddine A.
Published: July 2010

A systematic decision analytic methodology for providing insight into horizontal well placement decisions is presented. These decisions require access to real-time data and to input from subject-experts on the team and from the decision-maker. The available information and outcomes of alternatives are associated with uncertainty. Furthermore, the decision-maker may have multiple objectives, such as future productions, wellbore configuration, and drilling costs. The methodology uses Bayesian decision networks, also known as influence diagrams, to frame, analyze, and support operational decisions.

Influence diagrams are compact graphical representations of decisions and are based on decision and probability theories. They rigorously illustrate the interrelationships among decisions, key uncertainties, and value functions. Furthermore, they allow incorporating sensor readings, sub-surface model outputs, and experts' knowledge, which enables probabilistic inference and decision support in real-time contexts. Finally, the influence diagrams models may be used to calculate value of information and of control.

In this paper, we focus on supporting well placement decisions involving multiple objectives. We explore the feasibility and suitability of using two potential extensions of the influence diagrams: (1) multiple-attribute utility influence diagram and (2) multiple-objective influence diagram. Using the methodology, the example shows that both extensions have the potential to improve the decision-making process within the multi-disciplinary team. They can provide further insight into decisions by ranking the value of information for key uncertainties from the perspective of different sub-groups of the drilling team.

Following a systematic decision analytic methodology, in particular, decision analysis cycle, and applying influence diagrams in drilling operations would create value by reducing losses (materials and drilling/completion processes' downtime) and increasing future production through optimized well placement while drilling.
A Neural Network Approach for Real Time Evaluation of Sandstone Strength
Authors: Soroush H. , Tokhmechi B.
Published: July 2010

The integrity of the wellbore plays an important role in petroleum operations including drilling, completion and production. Oil and gas industry has been always suffering from wellbore stability and sand production problems which have been costly and time consuming to tackle. Having a good knowledge of formation strength and earth's stresses is the key for evaluation of well integrity during both drilling and production. Formation strength is usually obtained throught either experimental tests or interpretation of petrophysical logs. However, on one side, in most cases the core strength databases are limited, discontinuous and are often biased towards stronger intervals; on the other side, petrophysical logs can be adversely affected by drilling fluid, pore fluid and borehole shape and require to be calibrated against laboratory measurements. It raised the idea of approximating rock strength from some physical or petrographical properties of rock, which are more convenient to measure, even on drilling cuttings.

This paper aims to establish empirical relationships between sandstone petrographical features and the unconfined compressive strength (UCS). A comprehensive laboratory study was performed and reasonable correlations was established between the UCS values and a number of petrographical properties (including cementation degree, grain shape, median grain size, nature of graingrain contacts, average numbers of grains in contact, quartz content, clay content, sorting, and visual porosity).

Finally a multilayer perception neural network (MLPNN) model was designed to enable estimation of UCS using petrographical data. A workflow was presented for near real-time evaluation of formation by visual inspection and characterisation of drilling cuttings at rig-site with implication for controlling wellbore failure during drilling and production.
Using Optimization Techniques for Determining Optimal Locations of Additional Oil Wells in South Rumaila Oil Field
Authors: Al-Mudhafar Wathiq J. , Al-Jawad Mohammed S. , Al-Shamma Dunia A.
Published: July 2010

Determining the optimal location of the wells is a crucial decision to be made during a field development plan. A reservoir simulator called "SimBest II" has been used in the present study. The oil field under study is a sector of South Rumaila oil field/main pay. Two methods of optimization have been adopted in the present study. The first one is manual optimization and the second method is automatic optimization. Genetic Algorithm (GA) was used as the automatic optimization method to find the best number and locations of the wells. Genetic algorithm depends on the principle of artificial intelligence similar to Darwin's theory of Natural Selection. The genetic program is coupled with the simulator in order to re-evaluate the optimized wells at each iteration. The genetic algorithm computer program gave results similar to the results that are obtained by the manual method with less computer time. Both methods have been adopted according to the aspects of net present value (economic evaluation) as objective function. According to the relationship between net present value and future production time, the abandonment time was estimated before end of December 2014 for all proposed future scenarios. The optimal future scenario was with water injection of 15000 surface bbls/day per well. The optimal number of additional wells for this case was nineteen wells, but it may be impossible to drill such a number of wells in the one year especially in Iraq. Moreover, that an alternative option of drilling three wells with reduction of 0.07399 % in NPV has been considered. This option is also suggested if the surface injection facilities cannot handle the injection of 15000 surface bbls/day. The optimal number of additional wells for this choice is also three wells.
Surfactant Stimulation to Increase Reserves in Carbonate Reservoir: "A Case Study in Semoga Field"
Authors: Rilian Nova Arthur , Sumestry Meiliza , Wahyuningsih _
Published: July 2010

Semoga field, which produces from Baturaja (carbonate) formation, has experienced a decline in production and has a high water cut (WC). The current average water cut in Kaji-Semoga field is 86%, while several producing wells have above 95% WC and even 100%. In 2007, Lemigas conducted a laboratory study to determine the wettability of Baturaja formation (BRF), the result of which was that BRF indicated very oil wet characteristics. However, after being immersed in surfactant, core samples became less oil wet. This test shows that trapped oil can be recovered using tertiary recovery methods. One option for confirming the laboratory test result is to use surfactant huff & puff method in a pilot project.

Surfactant is a surface active agent compound which has the ability to reduce the surface tension between the rocks, produced water and crude oil so that wettability may change. The surfactant type to be used on BRF formation is non-ionic. The pilot huff and puff project was conducted on wells X-1 & X-2. High WC wells with low WC at initial (early production) and high liquid production were selected to minimize risk and to yield more oil. This project was evaluated using pressure build-up test (transient analysis) and production performance monitoring before and after the surfactant stimulation job. An economic analysis was also conducted

As a result of employing surfactant stimulation, Semoga Field yielded NPV @ 3 month 24,013 USD with a pay-out time (POT) of 11 days. Oil gain would be more significant if the technique was implemented on high production wells.
Asphaltene Precipitation Study during Natural Depletion at Reservoir Conditions
Authors: Afshari S. , Kharrat R. , Ghazanfari M. H.
Published: July 2010

This study concerns with experimental investigations of asphaltene precipitation at reservoir conditions of a crude sample from an Iranian oil reservoir during pressure depletion. High pressure high temperature set up and filtration method was used to quantify amount of precipitated asphaltene at different pressures. In addition the effect of temperature on asphaltene precipitation during pressure depletion has also been examined. The experimental results have been used to develop the asphaltene precipitation model with the application of commercial software as well.

The movement of production systems to deepwater and subsea environments in recent years has increased the importance of fluid property related flow assurance issues. Fluid property variations that commonly occur during the production of oil, such as changes in pressure, temperature and composition, can precipitate asphaltenes. Asphaltene precipitation causes severe problems in reservoir oil production which is highly costly and laborious to remediate. Optimizing production in this case requires knowing the conditions under which asphaltenes will remain in solution. Experimental measurements at reservoir conditions play an important role in understanding asphaltene behavior as well as developing and justifying asphaltene models.

The results of this study confirm that asphaltene precipitation increases when temperature decreases, this can be interpreted as a result of variation in volume fraction of species when temperature changes. After the pressure onset, asphaltene precipitation increases with reduction of pressure and reaches to a maximum near the bubblepoint. Furthermore reduction in pressure leads to asphaltene redissolusion due to light gas liberation. Also it is revealed that denser asphaltene components have tendency to precipitate initially.

The results of this study can be applied as criteria for designing successful production operation in order to avoid asphaltene problem and also for thermodynamic model development or modification.
Real-Time Production Optimzation for a Mature Onshore Field in Austria
Authors: Nederlof E. F. , Huber S.
Published: July 2010

This paper will describe the results of a study to implement a Real-time Production Optimization initiative for a mature onshore field in Austria.

Oil and gas have been produced from Austria since the 40's. At this moment OMV Austria produces roughly 40.000 boe per day from approximately 810 oil and 100 gas wells. The wells are located in a large and complex geographical area. The oil wells are mainly produced by means of artificial lift. The artificial lift systems in place are sucker rod pumps, gaslift, ESP's and PCP's. Average production for these wells is around 20 bopd with a water-cut of roughly 95%.

In order to reduce OPEX, optimize workflows, increase production and further improve HSEQ performance the level of automation and control of the wells has to be increased. Additional sensors (Pressure, Temperature and Pump-Off controllers) have been defined for the different artificial lift methods. To achieve a greater operating flexibility all Beam pumps will be equipped with a Variable Speed Drive. Also flow control valves of the gaslift system need to be replaced. Besides the sensors it was identified that the power grid and communication need to be upgraded. In a number of cases the well sites have to be adjusted as well. The generated data will be analyzed on a software platform that allows Real-Time Production Optimization and provides warnings when wells are running outside the ideal operating envelope.

Costs for the defined scope of work have been gathered and evaluated and several implementation scenarios have been investigated. The dramatically changed economical situation as well as the large investment requirement for full field implementation did not proof to be economical. However a pilot project will be executed in 2010 to confirm the economical and technical assumptions.
Neural Networks in BHCP Prediction Performed Much Better Than Mechanistic Models
Authors: Ashena Rahman , Moghadasi J. , Ghalambor A. , Bataee M. , Ashena Rahim , Feghhi A.
Published: July 2010

Two phase flow applications in petroleum industry are so widespread. It is a fact that UBD precise bottomhole pressure maintenance ascertains UBD success. UBD hydraulics design, especially for inclined trajectories, is a real challenge. This is greatly dependent on the pressure drop in the annulus.

Two phase flow through annulus is an ambiguous area of study to evaluate the bottomhole pressure. Two phase flow correlations on which most of UBD simulators based on over predict and also make extrapolation risky. Although Mechanistic approaches increase the frequency for designing two phase flow systems in pipes, modeling them through annulus by using the hydraulic diameter concept is not so successful. For this reason, their corresponding errors are not small. Therefore, in this paper, Artificial Neural Network is made use of to evaluate BHP in the inclined annulus using two major Iranian Oil Fields. To compare BHP found by neural network, Naseri et al mechanistic model which is a popular mechanistic model for these two fields is applied.

ANN shows to perform much better than Naseri et al mechanistic model. The results show that neural network can estimate bottomhole pressure with an error of less than 20%. This proves that in case of existence of measured BHP while under balanced drilling, it is worth to use ANN to simulate BHP rather than mechanistic modeling or correlations.

ANN is highly shown to be useful for solving the non-straightforward problem of two phase flow in annulus. Few jobs have been done to prove the superiority of ANN to mechanistic modeling and correlations in terms of pressure prediction especially in under balanced drilling.
The Effect of Reservoir Wettability on the Production Characteristics of the VAPEX Process
Authors: Rezaei N. , Mohammadzadeh O. , Parsaei R. , Chatzis I.
Published: July 2010

Based on the pore-level visual investigation results of vapor extraction (VAPEX) process in etched glass micromodels, two major pore-scale recovery mechanisms were found responsible in the drainage of live oil, namely, 1) the drainage type displacement mechanism of gas invasion in a pore filled with oil and 2) the film flow drainage mechanism in the corners of pore space invaded by gas. Inspired by the role of film flow drainage in the recovery performance and production history of the VAPEX process, wettability was expected to play a profound role in the drainage of live oil by the stated mechanisms. Therefore, we examined the impact of fractional wettability on production characteristics of a VAPEX process at a macro scale. Conventional VAPEX experiments were conducted in a 220 Darcy random packing of glass beads in a rectangular physical model and used n-pentane to recover the Cold Lake bitumen from the oil saturated model. The composition of packed bed was changed from completely water-wet glass beads to completely oil-wet treated glass beads, at different compositions obtained by mixture design. It was found that the live oil production substantially increased (35-40%) from water-wet conditions to the extreme case of oil-wet conditions. A percolation threshold at about 65% oil-wet composition (35% water-wet) was found, after which the live oil production rate during VAPEX process did not change with further increase in the volume fraction of oil-wet beads. The production rate of VAPEX linearly decreased with increasing the volume fraction of water-wet beads over the 30% value in a random packing. It is believed that above the percolation composition, the oil-wet regions dominate the film flow process as there will be a continuity of high conductivity film through oil-wet regions, as a result of thicker (in size) bulk oil films between particles. The solvent content, the solvent-to-oil ratio (SOR), and the residual oil saturation did not correlate to the wetting composition of packing. The values obtained for solvent content were 47-49% (g/g), for the SOR 0.9-0.95 (g/g) and for the residual oil saturation 7-to-10 % of pore volume.