bluuebunny/crossref_metadata_2025 huggingface dataset:
Protect and Then inject: Optimized Well Fluids Successfully Drill Depleted Reservoirs To Store Gas
Authors: Vickers Stephen , Bruce Stephen , Hutton Alistair , Nunzi Paolo
Published: April 2012

A major operator has initiated the data-acquisition campaign in the southern North Sea for a future storage facility capable of holding 5 billion m3 of gas. It is estimated this venture will double the existing gas supplies stored in the UK and represent more than 5% of its annual gas demand. As North Sea gas production decreases and the UK becomes more dependent on imports, the ability to store gas has become an important part of the UK energy policy.

Drilling into depleted reservoirs for gas storage produces several major technical problems and issues that must be addressed. This field is a pressure-depleted reservoir with a differential pressure equivalent to 7.3 lbm/gal between the drilling fluid's hydrostatic pressure and the reservoir pressure. This differential must be controlled to eliminate the risk of differential sticking, downhole losses, and hole collapse.

Because of the reservoir depletion, it would be impossible to backflow and clean up the near-wellbore region without a postdrill-in treatment fluid to remove the fluid filter cake and water-wet all the surfaces for gas injection. To ensure project success and usable fluid designs, reservoir conditions were simulated in the laboratory and fluid parameters were altered to provide the optimum properties to minimize the future risks.

The paper discusses in full the laboratory design process, the verification of the drill-in and treatment fluids as being fit-for-purpose, and their successful application in the field. Initial well testing suggested that the expected injection rates of 500 scf/min at 300 psi were exceeded, with rates of 750 scf/min at 280 psi reported.
Interwell Tracer Tests To Optimize Operating Conditions for a Surfactant Field Trial: Design, Evaluation, and Implications
Authors: Cheng Hao , Shook G. Michael , Taimur Malik , Dwarakanath Varadarajan , Smith Bruce R.
Published: April 2012

Enhanced oil recovery (EOR) by surfactant flooding is the key to unlocking the next billion barrels of oil for Minas, one of the world's largest waterflood fields. An interwell tracer test (ITT-1) was performed before a surfactant field trial (SFT) to ensure well injectivity, demonstrate pattern confinement, quantitatively describe interwell connectivity and sweep efficiency, and provide sufficient data for reservoir evaluation. The tracer test was designed by numerical simulation. The test started in November 2009 and was terminated in February 2010.

Analytical interpretation based on moment analysis and numerical reservoir simulations was conducted to evaluate ITT-1 results. Interpretation of the test results indicated various operational and reservoir properties that would have likely led to failure of the surfactant pilot. Hydraulic control of the SFT pattern was not achieved; in fact, less than 20% of one tracer was recovered. Many small-scale heterogeneities were identified that led to a lower-than-expected reservoir volume contacted. Unexpected communication between the target sand and the underlying sands outside the pattern also contributed to low tracer recovery and low swept volume. The tracer test was history matched, and additional features were incorporated in the reservoir model, and a new tracer design (ITT-2) was optimized to correct low sweep efficiency and poor hydraulic control. New information from ITT-2 will be used to further optimize operating conditions for SFTs.

Failure to conduct the tracer tests would have likely revealed these unfavorable reservoir and operational conditions during the SFT. Had oil recovery been poor (because of low swept volume), it would have erroneously been attributed to a poor SFT rather than to the true causes. ITT-1 is considered successful because it allowed us to redesign injection/hydraulic control during the relatively inexpensive tracer test and thus evaluate the surfactant trial without bias.
Lost Circulation Corrective: Time-Setting Clay Cement
Authors: Messenger J.U. , McNiel J.S.
Published: April 2012

In the drilling of oil wells the control and prevention of lost circulation of the drilling fluid is a problem which is frequently encountered; in many cases existing materials and methods for alleviating this condition have not been adequate. For severe cases of lost circulation in which the simpler methods, such as application of various bridging materials to the mud system, have proven unsatisfactory, a new material and method for applying to the loss zones have been developed which appear to be superior to existing techniques in many respects.

The material, called a clay cement, is capable of being handled as a drilling fluid after initial mixing of the solid ingredients with water and may be pumped down the drill pipe and squeezed into loss zones. After a short period, the material develops a very high gel strength which seals off the zone against further losses of the drilling fluid.

In field tests, the process has been demonstrated to be a very effective method for combatting lost circulation.

Introduction

Methods of treating lost circulation in rotary-drilled wells by the addition of special materials to drilling fluids have long been in the process of development and are continuing to improve. However, the annual drilling costs which can be traced directly to lost circulation difficulties still run into the millions of dollars. The loss of mud materials into highly permeable zones may range up to $50,000 per well in some areas. In addition to mud costs, excessive requirements of casing, cement, rig time, and the attendant blowout hazards further emphasize the importance of the need for improved methods of combatting lost circulation. The shortcomings of presently-used materials and methods have led to the development of a new lost returns material in the form of a timesetting clay cement. In field tests this material has proven very successful in plugging off loss zones, which other more conventional materials had failed to do.
Experimental Study for Optimizing Injected Surfactant Volume in a Miscible Carbon Dioxide Flood
Authors: Afonja Gbolahan , Hughes Richard G. , Shetty Shrinidhi
Published: April 2012

One major drawback in the implementation of CO2/surfactant enhanced oil recovery is the high cost of the surfactant volume needed and the extrapolated amount of surfactant required for use in the field. Therefore, there exists a need for a methodology to evaluate the most economic surfactant volume that will lead to optimum oil production.

This paper presents the results of laboratory experiments that were designed to study the performance of foam injection and to obtain information on the parameters that will be utilized in a future modeling study to determine the minimum but most effective volume of surfactant needed for optimum foam generation and hence oil recovery in a porous medium. The effect of reservoir pressure and surfactant concentration is studied.

Carbon dioxide and surfactant solution were co-injected into Berea sandstone core that was saturated with brine and oil after a waterflood process. Some of the values of parameters utilized in the experiments include surfactant concentrations of 0.1 wt % and 0.5 wt %, average back pressure of 2350 psi and total flowrate of 0.4 cm3/min, with CO2 injected at 0.3 cm3/min and surfactant concentration at 0.1 cm3/min, which results in a volumetric flow ratio of 3:1 and foam quality of 75%.

Results show that at a higher surfactant concentration, more oil was recovered, and a steady increase in pressure difference was observed. This indicates that foam was formed, which was also seen at the production end of the system. The foam created during the experiments with the 0.1 wt % surfactant concentration, on visual inspection, appeared to be weaker than that formed in the case of the 0.5 wt % concentration.
Upgrading Crude Oil by a Deasphalting Technology Under Non Severe Operating Conditions
Authors: Álvarez M. , Chirinos M. , Silva F. , Zabala A. , Perdomo L.
Published: April 2012

Because of very large reserves of heavy and extra heavy oil, mainly located in Venezuela, the development of technologies for recovering and treating these hydrocarbons becomes a key factor in the strategic valorization of those resources. In accordance with these needs, has been developed since 2005 a technology named INT-MECS®. INT-MECS® technology is a heavy and extra heavy oil deasphalting process for streams coming from waste pits and different production areas; it is based on a liquid - liquid extraction unit, using low molecular weight paraffin solvents under not severe operating conditions (temperature and pressure).

INT-MECS® technology has been evaluated at laboratory scale under a batch scheme and finally, using a 250BOPD pilot plant facility, located in Jobo field (Morichal, Venezuela); generating encouraging results with high crude conversion and an improvement in the physicochemical properties of the original fluids coming from PETROMONAGAS upgrader and Morichal's production unit: reduction of viscosities, increase in API gravity (14 – 21 °API deasphalted oils from heavy and extra heavy oils), asphaltene content reduction, desulfurization and demetallization, getting better results in transportation and refining processes.

After having passed the stages of laboratory scale and pilot scale tests, this technological solution is currently entering in a visualization study for field deployment in existing upgrading facilities schemes in the Venezuelan oil industry.
Methodology of the Juxtaposition Analysis for Fault Structural Traps
Authors: Carrasco J.
Published: April 2012

The new challenges of the oil exploration focused to the location in closed traps against faults in deep waters. The methodology has been developed for the juxtaposition studies by faults in structural traps that it analyzes the sealed surface, which is like an evaluation technique that quantifies of efficient way, the exploratory risk related with the sealed and the hierarchy of the prospective objectives in an opportune way speeding up the answer capacity for the taking of decisions that imply a high consumption of time and money. This summary synthesizes the method for the construction of the Allan's diagrams of juxtaposition. It consist of using computational tools that optimize the times of elaboration. The work flow has been directed in the realization of the juxtaposition (2D/3D) diagrams that it allows to evaluate the efficiency of the lateral sealed in traps against fault segment and obtaining of hydrocarbon new wells. To determine the capacity of sealed for the faults the seismic interpretation it is needed in depth of the roof-ceiling horizons, as well as the behavior of the segments of faults. Later on, it is carried out the seismic mapping of each geologic element to analyze. The principal stage of the methodology is the obtaining by means of an operation vector subtraction of the intersections of the objective horizon so much of the roof block and the ceiling block on the fault surface in the setting. Once certain, the vertical component of the fault jump for each one of the exploratory objectives. It proceeds to elaborate Allan's (2D) diagram in a profile made up of the integration of the intersections of all the objectives for each contour of fault surface. Finally, It spreads in perspective the geometry 3D of each fault plan with their intersections type and their impact in juxtaposition. This method has been proven with success in the hydrocarbon locations on deep waters of area the Region Marina from Gulf of Mexico.
Colloidal-suspension Flow in Rocks: A New Mathematical Model, Laboratory Study, IOR
Authors: Aji K. , McLindin C. , Saha A. , Le K. , You Z. , Badalyan A. , Bedrikovetsky P.
Published: April 2012

A new analytical model for deep bed filtration of colloidal/suspension transport under size exclusion particle capture is developed and validated. The laboratory tests on suspension flow in engineered porous media, which simulate the injection of colloidal and particle suspensions in rocks, have been carried out. The model was successfully matched with the laboratory coreflood results, predicting particle breakthrough and stabilised concentration. Compared to the previous population balance model, the present one provides a better prediction of the normalised particle concentration versus jamming ratio. The sensitivity analysis shows that among the three parameters: the mean pore radius, the standard deviation and the inter-chamber distance, the first one has the largest effect on the outlet concentration.
A Comprehensive Approach on Determining Correlations between Sonic- and Density-Log Measurements from the Gulf of Mexico and North Sea Fields for Improved Reservoir Descriptions
Authors: Bai M. , Li G.
Published: April 2012

In the past, numerous relations between sonic velocity (i.e., an inverse of sonic travel time, DT) and rock density were developed that were suitable for certain fields or certain rocks only. In this paper, the correlations between sonic- and density-log measurements were investigated again using the data information from multiple fields in the Gulf of Mexico (GoM) and North Sea (NS). For sandstone-shale sequences, the dominant linear relationships between travel time (DT) and formation density (RHOB) were observed and compared with the popular Gardner's method (Gardner et al. 1974) along with other known methods. The implications of data clusters distinguished by formation lithologies and rock mechanical strengths were revealed from a cross-plot analysis. The probabilities and uncertainties of the developed correlations were determined using the actual histograms from the collected data of the GoM and NS fields coupled with Monte Carlo simulations.
An Analytical Equation to Predict Gas-Water Relative Permeability Curves in Fractures
Authors: Chima A. , Geiger S.
Published: April 2012

Naturally fractured reservoirs (e.g., carbonates) and hydraulically fractured reservoirs (e.g., shale gas) contain a major part of the world's remaining hydrocarbon reserves yet suffer from low recovery. The accurate perdiction of multi-phase flow in fractures is hence highly important. In 1966, E. S. Romm proposed an equation to calculate oil-water relative permeability curves in fractures based on experimental results using kerosene and water. He suggested that relative permeability is a linear function of saturation (krw = Sw, krnw = Snw). However, it is not clear if linear relative permeability curves can be used for gas-water flow in fractures because there is mounting experimental evidence that in this case relative permeability curves in fractures are non-linear function of saturation. Despite this fact, Romm's equations continue to be widely used in most reservoir simulators to calculate relative permeability curves in fractures for gas recovery processes, which may lead to significant errors when predicting gas recovery from fractured reservoirs, particularly unconventional reservoirs such as shale gas.

In this work, we hence use the concept of shell momentum balance, Newton's law of viscosity and the cubic law for flow in fractures to derive a new analytical equation to calculate relative permeability curves in fractured systems for gas-water two-phase flow. This derivation shows that the relative peremeability curves should be non-linear functions of not only saturation but also viscosity. Our proposed equations, which can be implemented straightforwardly in commercial reservoir simulators, are validated with laboratory data measurements and show much better agreement compared to Romm's equation. We further demonstrate the impact of Romm's and our relative permeability models on gas recovery and time to water breakthrough: Romm's equation will overestimate gas recovery and time to water breakthrough by a factor of two, which is significant considering the low recovery typically encountered in naturally and hydraulically fractured reservoirs.
Cementing Unconsolidated Sandstone Formations with Coexisting Oil and Water
Authors: Robles J. , Sapag F. , Sanchez L. , Morris W. , Peacock H. , Bravo J.
Published: April 2012

Oil wells with unconsolidated formations where oil and water coexist require special attention during drilling, well completion and production stages. This is the case of a heavy oilfield located in the Neuquina Basin, Argentina, where for many years, periodic cement squeeze jobs were needed to avoid near-wellbore water channeling. In addition to formation unconsolidation, this reservoir has high porosity and permeability as well as poor lithologycal barriers.

When the top of the oil producing zone is perforated and evaluated by swabbing, viscous oil carrying formation sand is initially produced. After a short period of time (days), water cut rises to values close to 100 % promoted by the high mobility ratio. This response impedes a profitable production of these oil wells.

After analyzing open and cased-hole logs, as well as production history data, the hypothesis for the short term water invasion was identified as near-wellbore channeling caused by sand production. This process was aided by formation weakening due to its interaction with drilling and completion fluids.

The solution to this problem was based on a primary cementing procedure that included specially designed slurries containing polymeric admixtures. Effective formation isolation, bonding and near-wellbore consolidation was achieved by allowing these additives to leak-off into the unconsolidated formation. This paper presents the experimental tests performed to develop the procedure and the field results obtained after five successful cementing jobs. Sand production was significantly diminished and no cement repairs were needed after the first six months of production.
Transient Pressure Behavior for Dual Porosity Low Permeability Reservoir Based on Modified Darcy's Equation
Authors: Xu J. , Jiang R. , Xie L. , Yang M. , Wang G. , Liu J.
Published: April 2012

With further progress of oilfields' development in China, more and more low permeability reservoirs are being put in production. However, fluid flow in low permeability porous media no longer obeys Darcy's law, so traditional well testing interpretation methods may cause error in estimation of the reservoir parameters.

This paper describes problems encountered when analyzing transient pressure tests in low permeability reservoir. The equation to describe the non-Darcy flow was given according to experimental method and two factors were introduced into the equation to improve the Darcy's law. Based on the modified model, the theoretical well test model for dual-porosity media in low permeability reservoirs with complex fractures was derived which allows for the influence analysis of non-Darcy effect. The model was solved by numerical method and the log-log curves for the pressure responses were plotted. Sensitivity analysis shows that the pressure responses for both Darcy flow and non-Darcy flow conditions are the same for the following parameters: wellbore storage, skin factor, ratio of storativity, and interporosity flow coefficient. Non-Darcy flow mainly affects the transition section between the pure wellbore storage and radial flow region, and the pressure derivative curves exhibit a gentle transition region compared with the Darcy's flow. These type curves give a better interpretation of well testing pressure response in low permeability reservoirs.
Non-Petrochemical Surfactant for Enhanced Oil Recovery
Authors: Majidaie S. , Mushtaq M. , Tan I. M , Demiral B. , Lee S. Y.
Published: April 2012

A new sulfonate surfactant from non-edible vegetable oils is developed. The sulfonate surfactant was synthesized from C16-18 fatty acid and evaluated for stability, Interfacial Tension (IFT) and core flooding experiments for its capability to enhance oil recovery. The feedstock is composed mostly of unsaturated fatty acid derived from jatropha curcas oil which can be converted to fatty acid methyl ester. The methyl ester is epoxidized and hydrolyzed to hydroxyl groups, which subsequently were sulfonated to form a product named Methyl Ester Sulfonates (MES).

The performance of the synthesized surfactant was studied for its stability, IFT and core flooding experiments. The stability shows that surfactant solution in produced water is clear and free of precipitation. Based on IFT experiments optimum surfactant concentration is 1 wt% which resulted in a lowest possible IFT of 0.19 mN/m in the presence of Na2CO3 as alkali.

By conducting a displacement test, an improvement in oil recovery is observed. Surfactant floods perform to test how effectively a surfactant formulation can recover oil on tertiary oil recovery. The results confirmed that there is a possibility of developing new surfactants from vegetable oils. It can obviate the need for using petrochemicals substances in synthesizing surfactants.
Utilization of Charged Particles as an Efficient Way to Improve Rheological Properties of Heavy Asphaltic Petroleum Fluids
Authors: Alfi Masoud , Da Silva Paulo F. , Barrufet Maria A. , Moreira Rosana G.
Published: April 2012

High energy electron particles were utilized to improve the rheological properties of heavy asphaltic petroleum fluids and upgrade them into lighter, and more utilizable, fluids. Heavy oil reserves, as one of the most abundant sources of energy, have attracted considerable attention during the last decades. However, high viscosity of such fluids always poses problems during production and transportation operations. Complex hydrocarbon molecules in heavy petroleum fluids can be affordable sources of energy if we can find a way to convert them into components of simpler structure in a cost-efficient process. While high energy demand of conventional thermal and thermo-catalytic process casts doubts on the application of such methods, emerging electron beam upgrading technology appears to provide promising achievements as a novel hydrocarbon treatment process. Radiation thermal cracking was observed to reduce the viscosity of highly asphaltic petroleum samples more than the conventional thermal cracking method. Simulated distillation analysis showed higher concentrations of lighter components in radiolyzed samples, which indicated the intensified cracking as a result of electron irradiation. Stability of the products with time is one of the main concerns because samples with altering properties may cause difficulties after the upgrading process. The viscosity of thermally cracked samples showed a substantial increase with time, while aging investigations on radiation thermal cracking products demonstrated stable properties.
Facilitating Treatment of Produced Water from Offshore Platforms by an Oxidation/Coagulation/Flocculation Approach
Authors: Cardoso C. , Filho F. , Mahmoudkhani A. , De Caprio A. , Costa M. , Nair M.
Published: April 2012

On average, 3 barrels of water is produced for every barrel of oil in offshore platforms. The water must be treated for reuse or discharge. Oilfield produced water contains a diverse mixture of compounds that varies from formation to formation. Of particular importance are the organic compounds classified as "Oil and Grease" (O&G) by the Clean Water Act. These compounds must be removed to meet environmental, political and operational goals. Excessive O&G in re-injected water can foul the equipment or the formation. Discharged water must meet legal or contractual standards often less than 30 mg/L per day. Governmental restrictions are put on the quality of water-discharge to sea, but the self-imposed corporate guidelines provided by the oil-companies are often more stringent. As a result a water treatment facility running smoothly is important, and a fitting control structure provided a good tuning strategy is essential in reaching this goal. When selecting produced water treatment technologies, one should focus on reducing the major contributors to the total environmental impact. These are dispersed oil and semi-soluble hydrocarbons, alkylated phenols, and added chemicals. Experiments with several samples of produced water from South America offshore platforms have been performed. These experiments were designed to find efficacy of treatment strategies using a combination of oxidation, coagulation and flocculation methods. Experiments were conducted at various pH values (6 – 9) with samples containing TOG of 17 – 198 mg/L and TSS of 100 – 1000 mg/L. With optimal and low dosage of coagulant/flocculant, oxidation process and treatment sequence, TOGs can be easily reduced to below discharge limit. Results from our studies indicate the viability of this approach for water management in offshore platforms with no need for capital equipment.
Environmentally Friendly Dispersants for High Temperature Invert-Emulsion Drilling Fluids Weighted by Manganese Tetraoxide
Authors: Rehman Abdul , Moajil Abdullah M. , Nasr-El-Din Hisham A. , Al-Bagoury Mohamed , Steele Christopher D.
Published: April 2012

This paper evaluates different environmentally friendly dispersants in invert-emulsion drilling fluids that can be used to drill HP/HT wells. The drilling fluid is weighted by manganese tetraoxide (Mn3O4) particles, which have a specific gravity of 4.8 and a mean particle diameter of 1 µm. Manganese tetraoxide has different wetting properties and surface chemistry than other weighting agents. Hence, there is a need to find dispersants for manganese tetraoxide that give reduced sag, reduced rheological properties, and low fluid-loss at HP/HT conditions. This is particularly important for deep wells with narrow operating windows between pore-pressure and fracture pressure gradients.

The stricter global environmental regulations mandate the dispersants to be environmentally friendly, e.g. within OCNS group D or E.

First, oil compatibility tests and particle settling time experiments were conducted on several dispersants. From the experiments, we identified 3 oil-compatible dispersants that gave the longest settling time in base oil and belonged to OCNS group D. We investigated the effectiveness of the selected chemicals in dispersing manganese tetraoxide at HP/HT conditions. Samples of 1.9 and 2.4 SG drilling fluids were prepared and tested. Drilling fluid samples were statically aged at 400°F and 500 psi for 16 hours. Sag and rheological measurements were taken before and after aging to determine the effect of HP/HT conditions on fluid properties. Sag tendency was measured by viscometer sag shoe test (VSST). Then, HP/HT dynamic filtration tests were done at 500 psi differential pressure and 300°F to determine HP/HT dynamic fluid-loss.

We have found that one of the dispersants (nonionic) with a concentration of 8 and 16 g/l for 1.9 and 2.4 SG, respectively, gives low rheological properties and reduced sag before and after static aging. It also gives the lowest fluid-loss of the selected dispersants. For 2.4 SG fluid, 10-minute gel strength was reduced from 50 to 32 lb/100ft2, plastic viscosity from 37 to 25 cp, sag from 0.249 to 0.135 lbm/gal, and the fluid-loss at 300°F was reduced from 44.4 to 39.6 cm3, with the addition of the dispersant. This dispersant prevents agglomeration of particles, thereby reducing fluid rheological properties, sag, and fluid-loss.
State of the Art and Future Trend of Drilling Fluid: An Experimental Study
Authors: Apaleke Adeleye Sanmi , Al-Majed Abdulaziz , Hossain M. Enamul
Published: April 2012

In its endeavor to provide a sustainable flow of hydrocarbon energy, the Petroleum industry has been recognized by the general public as an industry that has negatively impacted the environment as a result of using either harmful materials or risky practices. This leads the industry to continuously invest in R&D to develop environmentally friendly technologies and products. For any new technology or product, the current R&D trend is toward the development of sustainable practices and expertise. Drilling fluids are necessary for drilling oil and gas wells. Unfortunately drilling fluids have become increasingly more complex in order to satisfy the various operational demands and challenges. The materials used in the process to improve the quality and functions of the drilling fluids, contaminates the subsurface and underground systems, landfills, and surrounding environment. Due to the increasing environmental awareness and pressure from environmental agencies throughout the world it is very important to look back to the drilling fluid technology to reassess its progress. To sustain its position as an environment friendly industry, the petroleum industry should make forward steps to improve its practices. This article outlines the state-of-the-art of drilling fluids. The major types of drilling fluids, their strengths, limitations, and remedies to limitations are discussed. It also presents the current trend and the future challenges of this technology. An experiment was conducted to develop an environment friendly drilling fluid which is found more convenient and user friendly based on sustainability concept. The results of the experiment show that 90/10 oil water ratio formulation has higher probability to consider as a sustainable drilling mud. In addition, future research guidelines are presented focusing on the development of environmentally friendly drilling fluids with zero impact on the environment. The paper concludes that future trend leads toward the development of sustainable drilling fluids.
Effect of Natural Fracture Properties on Production Variability of Individual Wells in Multiphase Oil Reservoirs
Authors: Lopez Bruno , Gonzalez Laureano , Aguilera Roberto , Garcia-Hernandez Francisco
Published: April 2012

Fracture properties that are responsible for production variability of individual wells in oil reservoirs are investigated with the use of multi-phase dual porosity models. Simulation work and sensitivity analyses are performed using Top-Down reservoir modeling, i.e., starting with a simple case that increases in complexity based on the understanding of basic reservoir properties. Fractional production variability plots (FPVP) are used to measure the degree of heterogeneity of the naturally fractured reservoir considered in this study. Straight lines or smooth curves close to 45 degrees in the FPVP indicate homogeneous reservoirs which can be single porosity or dual porosity with uniform fracture distribution. An increase in curvature in the FPVP indicates higher heterogeneity, particularly in the fracture system. Fracture characteristics such as fracture distribution, aperture, geometry and orientation are part of the sensitivity analyses as well as fluid characteristics and fluid-rock interaction. Fracture density and length are found to have the largest impact.

Results of this work are corroborated when compared with real data from a naturally fractured multi phase oil reservoir in Mexico. A variability distribution model (VMD) is used to match the simulated production history of the field on a FPVP plot. The FPVP curvature is found to be proportional to the simulated normalized standard deviation (NSD) of the cumulative well production. As a result two equations are developed that correlate both fracture density and length with the NSD, respectively. Scatter plots are used to identify the effect of each parameter on the NSD.

It is concluded that the variable distribution model provides a realistic assessment of heterogeneity in naturally fractured multi phase oil reservoirs and helps with characterization of the reservoir.
Improved Predictivity through Use of a 3D Integrated Seismic Water Saturation Model in the Sierras Blancas Formation
Authors: Ucan S. , Monti L. , Cersosimo D. S. , Claa R. A. , Montagna A. O. , Quintero A. I.
Published: April 2012

A 3D integrated saturation model was built for the Sierras Blancas Formation of the Neuquén Basin, Argentina. The saturation model was based on core, logs and seismic data. History match of reservoir pressure and well productivities were taken into account to accurately determine the gas in place and productive reservoir boundaries, specifically using 3D seismic water saturation in the gas condensate formation. The Sierras Blancas Formation is an eolian deposit. In tight, wet and diagenetically altered regions, the seismic inversion porosity and acoustic impedance based models were not adequate to describe the gas in place distribution. Further, the effective gas permeabilities in the tighter part of the reservoir are a strong function of the initial water saturation as evidenced by fewer condensate and water blocking problems of horizontal wells that navigated through low water saturation, high permeability regions. Any relationship between seismic impedance and porosity correlation degraded in areas affected by secondary diagenetic processes therefore necessitating the use of a saturation parameter. 30 vertical wells that had DT curves were selected based on their production and spatial location in order to establish a correlation between log saturation and seismic attributes. Seismic saturation cubes were generated by multiattribute seismic analysis and resampled into the simulation scale model. Log saturations were then co-kriged with the 3D seismic saturation. Water saturations obtained from the initialized simulation scale model were compared with the 2D saturation logs, the 3D seismic and the geological model scales. An objective function was defined to match the 3D seismic water saturation with the initialized simulation model water saturation. Model parameters were iterated until a satisfactory match with the initialized simulation model was obtained.

By focusing the saturation match at the initialization stage, seismic, geological, petrophysical and SCAL models were ensured to be consistent prior to the full history match. Well history matching was consequently achieved much more simply and quickly. This paper presents a new detailed methodology of 3D pseudo-seismic water saturation generation, modeling and simulation used to accurately define OGIP, the productive boundaries of the reservoir, and to design trajectories for new horizontal wells.
A Reservoir Management System for the World’s First Thermal Gas Oil Gravity Drainage Project
Authors: Rawnsley Keith , Ikwumonu Augustine , Bettembourg Solenn , Putra Pristwanto , Al-Ismaili Ibrahim
Published: April 2012

Thermally Assisted Gas Oil Gravity Drainage of a fractured carbonate heavy oil field in Oman is starting the full field phase. Unlike a normal steam flood, steam is used as a heating agent to enhance the existing gravity drainage mechanisms. The project has been piloted successfully.

The project start-up sequence consists of increasing off take from deviated producers followed by steam injection and aquifer pump-off. Steam will progressively fill the fractures whilst heated oil drains down in the matrix blocks and accumulates in an oil rim below the steam in the fractures. The fracture oil rim will be lowered by approximately 100m. Horizontal producers will be completed in the final fracture oil rim position.

As no analogues exist a large degree of flexibility has been incorporated in the field development plan to cover uncertainties including caprock integrity, erratic oil rim movement and heterogeneous steam distribution. To facilitate decision making an enhanced reservoir surveillance, modelling and management system has been built. Reservoir pressures, oil rim positions, temperatures and rock strain data are obtained from a range of observation wells. Further data are obtained from surface uplift, microseismic monitoring and fluid sampling. Static, fracture, dynamic and geomechanical reservoir models have guided the design of the reservoir surveillance program and underlie the operating guidelines for the reservoir. These provide operator reactions for a wide range of "what-if" events. A corporate real time data portal has been optimised for the unique requirements of this project allowing for analysis of all data streams. A system allows 3D display, through time, of reservoir data and model forecasts to ensure optimum performance analysis.

Initial application has resulted in identification of optimised well configurations and start-up sequence giving higher oil forecasts.

The learning is being applied further in Oman and has wider application.
Quantitative Remaining Oil Interpretation Using Magnetic Resonance: From the Laboratory to the Pilot
Authors: Mitchell Jonathan , Edwards John , Fordham Edmund , Staniland John , Chassagne Romain , Cherukupalli Pradeep , Wilson Ove , Faber Rien , Bouwmeester Ron
Published: April 2012

Laboratory and single well pilot nuclear magnetic resonance (NMR) logging results are obtained for an enhanced oil recovery (EOR) project using a common physics of measurement at both scales. Screening for chemical EOR efficacy usually begins in the laboratory before moving to single or multiple well field pilots. Laboratory experiments were conducted on a low-field bench-top NMR magnet with fluid injection protocols that matched the log-inject-log concept of the single-well in situ EOR evaluation (Arora et al. 2010). In situ measurements of the oil and brine saturations during the flood, by "diffusion-editing" protocols and by relaxation measurements alone, are shown to be in quantitative agreement with gravimetric assays of recovered oil. Spatially resolved T2 analysis (the laboratory equivalent of a standard NMR well log) revealed non-uniform oil saturation during the EOR process in short core plugs. The final remaining oil distribution is confirmed by a reservoir simulation in a geometry identical to the NMR-compatible core holder. In a region of the core-plug not influenced by end effects, complete recovery of the oil was observed, consistent with the the single-well in situ EOR evaluation. The quantitative estimates of remaining oil, using a tool-equivalent NMR protocol, demonstrate the potential for NMR logging of remaining oil in monitoring wells completed with NMR-transparent casing.
Using a new Intelligent Well Technology Completions Strategy to Increase Thermal EOR Recoveries–SAGD Field Trial
Authors: Bedry Mark , Shaw Joel
Published: April 2012

Well segmentation and instrumentation have been used to improve steam injection and production conformance in a completions strategy for a thermal-enhanced oil recovery (EOR) project by using intelligent well technology and interval control valves (ICVs). The initial field trial is ongoing in the injector of a Northern Alberta steam-assisted gravity drainage (SAGD) well pair. The development of the completion technology suitable for thermal conditions, initial field trial results and the plans for further development are described in this paper. The application modeling shows that, depending on the level of heterogeneity present in the reservoir, a 45% reduction in the steam-oil ratio and an almost 70% increase in recovery can be achieved in a SAGD process when both improved injection conformance and producer differential steam-trap control can be applied in a segmented horizontal well pair. A cost-effective, intelligent-well completion solution to achieve this segmentation and control has the potential to add substantial value to field developments through improved steam conformance. This will result in increased energy efficiency and oil recovery. The method under development is also applicable to a wide range of other thermal EOR processes such as cyclic steam stimulation (CSS), steam drive, and variations, including, for example, those involving solvent additives.

The initial field deployment in the injector well was initiated to prove the technology, to demonstrate the feasibility of modifying the steam distribution, and to obtain best practices for future developments. A successful installation and commissioning of the intelligent completion has validated the technology. Lessons learned are highlighted. Early injection test results and data show a significant increase in the understanding of the injection and production behavior in the well pair. A test program to optimize the distribution of the steam injection in the well is underway, and the results are discussed. The intelligent completion technology under trial and proposed further developments should enable more extensive use of downhole measurement and control in thermal EOR projects than has been possible to date.
Evaluation of the Efficient Displacement Pressure in a CO2 Pilot Feasibility Study in a Giant Carbonate Oil Reservoir
Authors: Clara Cédric , Ali Ahmed Elsayed , Sener Ilhan
Published: April 2012

This paper evaluates the impact of reservoir pressure on displacement efficiency when injecting CO2 injection in a super giant Abu Dhabi carbonate oil reservoir. The term Efficient Displacement Pressure (EDP) was defined to distinguish it from Minimum Miscibility Pressure (MMP). EDP has similar characteristics as MMP, resulting in very high recovery when the operating pressure exceeds EDP/MMP. The need for the EDP concept arose when evaluating feasibility of a CO2 injection project. During this evaluation, displacement by CO2 was found to be very efficient at pressures much lower than the saturation pressure, and multi-contact miscibility between the oil and the injectant could not be proven by classical slim tube experiments in the EDP pressure range. EDP was assessed using different analytical and modelling approaches in the absence of reliable experimental results: (i) Analytical means, (ii) Equation of State (EOS) PVT Softwares, (iii) 1D Compositional Numerical Modelling. Simulations were performed using a 10-component EOS, well tuned using a variety of advanced PVT experiments. The 1D model was designed to mimic a representative part of the field where the feasibility of the CO2 pilot project was being studied. Results from the different methods were analyzed and compared to properly assess the EDP range. Investigations showed that determining exact EDP values remains difficult, because the results strongly depend on the methodology used, the ability of EOS to accurately predict slim tube experiments, and the dependency of recovery factor on the grid size in numerical simulations. The sensitivity to water saturation and water blocking were not investigated here. However, in the defined EDP range, it was demonstrated that very high displacement efficiency and recovery can be achieved by injecting CO2 at an operating pressure in the identified EDP range. The recovery was found to be extremely high, even if the EDP range is below the saturation pressure, where miscibility is not necessarily guaranteed. This calls into question the general pre-requisite that operating above MMP is a necessary condition for the success of a CO2 injection project.
Stretching the EOR Boundaries: Thermal Trial in one of Petroleum Development Oman's Deep Reservoirs containing Heavy Oil
Authors: Mandhari Musallam. S. , Hinai Sulaiman , Hinai R. , Abdkadir R. , Salhi M.
Published: April 2012

A cyclic steam pilot has been conducted in one of Petroleum Development Oman deepest heavy oil fields. The field is considered beyond conventional and proven enhanced oil recovery (EOR) technologies. However, as the target reservoir contains several billion barrels of heavy oil, a number of potential unconventional EOR technologies have been identified and considered for trialling.

During the screening process and despite the technical challenges, cyclic steam soak stood out as the technology that can be trialled to provide valuable information to reduce subsurface uncertainties such as permeability distribution, fraccing potential, injectivity and hot oil production capacity. In addition the trial is a key enabler for potential other unconventional EOR technologies in this field.

This paper will provide an overview of the development strategy for maturing this heavy oil reserves. The initial planning and the selection of the least risk and fastest project delivery strategy were critical to the fast implementation of this single well cyclic steam soak trial (CSS). The contracting strategy and the selection of the fit for purpose industrial standards are included in the discussion. Specific topics addressed include selection of the right equipment for better water specifications and higher steam quality are addressed. In addition, cold injectivity test, the results of the early injection and production cycles, and the surveillance program are presented.
A CT Scan Study of Immiscible Foam Flow in Porous Media for EOR
Authors: Simjoo M. , Dong Y. , Andrianov A. , Talanana M. , Zitha P. L.
Published: April 2012

A systematic CT scan aided laboratory study of N2 foam in Bentheimer sandstone cores is reported. The aim of the study was to investigate whether foam can improve oil recovery from clastic reservoirs subject to immiscible gas flooding. Foam was generated in-situ in water-flooded sandstone cores by co-injecting gas and surfactant solution at fixed foam quality. It was stabilized using two surfactants, namely C14-16 alpha olefin sulfonate (AOS) and mixtures of AOS and a polymeric fluorocarbon (FC) esther. Effects of surfactant concentration, injection direction, surfactant pre-flush and core length on foam behavior were examined in detail. Stable foams were obtained in the presence of waterflood residual oil. It was found that foam strength (mobility reduction factor) increases with surfactant concentration. Foam development and, correspondingly, oil recovery without surfactant pre-flush were delayed compared to the case with pre-flush. Gravity stable foam injection caused a quick increase of foam strength and an incremental oil recovery almost twice that for unstable flow conditions. Core floods reveled that the incremental oil recovery by foam was as much as 23±2% of the oil initially in place after injection of 4.0 PV of foam (equals to injection of 0.36 PV of surfactant solution) compared with water flooding. Incremental oil recovery was only 5.0±0.5% for gas flooding at the same injection conditions. It appears that oil production by foam flooding occurs due to the following main mechanisms: (1) residual oil saturation to gas flooding is lower than to water flooding, (2) formation of an oil bank in the first few injected pore volumes, which coincides with a large increase of capillary number and (3) transport of dispersed oil by the flowing foam lamellae, leading to long tail production at a fairly constant capillary number. Observations of this study support the concept that foam is potentially an efficient EOR method.
Novelty in Smart-Water Screening and Designing
Authors: Sultani Billal , Horvath-Szabo Geza , Zeng Huang , Abdallah Wael
Published: April 2012

A customized HPLC methodology is developed to allow characterizing and screening the recovery change due to ionic variation of injected water. Extended contact time is needed to see the impact of electrolytes on oil recovery. We could not observe significant differences in oil release when hydrophobized calcite particles are flooded with seawater with or without sulfate. However, a significant recovery difference between water and 0.1M MgCl2 solution is detected, where Mg2+ solution is able to recover more oil than water.

The developed methodology here allows experiments to take place within few days to provide results, which allows many runs to be performed. The advantages of this technique compared to the currently available methodologies are due to the small sample sizes and ease of use. Many columns can be analyzed; the packing material can be changed to calcite, chalk, or silica. In addition, different types of hydrophobic layer / particles can be used to coat the packing material. Comparing different electrolytes to one another, and determining the effect of electrolyte concentration on oil recovery requires many experiments. Therefore, this technique could be useful to make studies faster and easier to validate the recovery theories.