bluuebunny/crossref_metadata_2025 huggingface dataset:
Production Comparison of Hydraulic Fracturing Fluids in the Bakken and Three Forks Formations of North Dakota
Authors: Fry Jessica , Paterniti Melanie
Published: June 2014

There have been extensive efforts to recover oil from the Bakken formation in North Dakota since it was discovered in 1951. However, these efforts were not particularly profitable until the 2000s when horizontal drilling and large, multistage hydraulic fracturing treatment methods were used. The new drilling and completions methods created a substantial increase to production, which escalated throughout recent years and created a demand for better, more efficient completions. One major component of these completions is the base fluid used for hydraulic fracturing treatments. This paper compares hydraulic fracturing treatments of a new, residue-free (res-free) hydraulic fracturing fluid to all other fracturing fluid treatments.

The res-free fluid system was presented in 2012 as a premier fracturing fluid and economic alternative to guar-based systems to increase the resultant fracture conductivity. Since 2012, more than 40 wells have been completed in either the Bakken or Three Forks formations of North Dakota using the res-free fracturing fluid. While initial cost savings were realized, the production results from these wells have not been extensively studied. This paper presents the findings of a study comparing production from wells treated with res-free fracturing fluid to wells treated with other hydraulic fracturing fluids.

Because the wells completed using the res-free system are widespread throughout North Dakota and belong to several different operators, choosing a specific study area was challenging. To overcome this challenge, a spatial sampling technique was used. Spatial sampling is a method for comparing a large group of wells to their direct offsets. For this study, spatial sampling was applied to compare wells completed using the res-free system to wells completed using other fluids. To normalize general completion methods, only wells completed since the beginning of 2012 are included in this study. Offset wells for this study are those within a 1-mile radius from the center well. The production data for all wells was obtained from public sources. The proppant amount and total fluid volumes were normalized per foot of lateral to minimize variables. Other factors, such as drilling placement, type of proppant, type of fluid, or compartmentalization can affect production; however, these effects are not considered during this study.
Experimental Study and Modeling of the Effect of Nanoconfinement on Hydrocarbon Phase Behavior in Unconventional Reservoirs
Authors: Wang Lei , Parsa Elham , Gao Yuefeng , Ok Jeong Tae , Neeves Keith , Yin Xiaolong , Ozkan Erdal
Published: June 2014

The pore sizes of shale and other unconventional plays are of the order of tens of nanometers. Based on the fundamental theory of thermodynamics, several studies have indicated that, in such small pores, phase behavior is affected by the capillary pressure and surface forces and is different from that characterized in PVT cells. No experimental evidence of this phenomenon, however, has been presented in the literature. In this study, we apply nanofluidic devices to visualize phase changes of pure alkane and an alkane mixture under nanoconfinement as a means to approach oil/gas phase behaviors in nanoporous rocks. Pure alkane starts vaporizing in the micro-channels first, and then the meniscus flashes into the nanochannels immediately after the complete vaporization of the liquid in the micro-channels. The vaporization of the ternary hydrocarbon mixture, however, is very different from pure alkane. Although the liquid starts to vaporize in the microchannels first, as expected, the meniscus cannot propagate into the nano-channels in a comparable time scale as the pure alkane. The reason is that the liberation of lighter components from the liquid phase to the gas phase in the micro-channels increases the apparent molecular weight of the liquid in the nano-channels, suppressing the bubble point of the remaining fluid. A modified flash calculation procedure that uses the sizes of micro-channels and nano-channels as the characteristic lengths and assumed contact angle can reproduce the vaporization propagation sequence in the experimental observations. Experiments and modeling presented in this paper provide the proof of the concept and promote the understanding of phase behavior in nanoporous unconventional reservoirs.
A Pattern-Based Approach to Waterflood Performance Prediction Using Knowledge Management Tools and Classical Reservoir Engineering Forecasting Methods
Authors: Artun Emre , Vanderhaeghen Maurice , Murray Paul
Published: June 2014

Estimating future performance of waterflooded reservoirs is a challenging reservoir engineering problem in complex reservoirs that are poorly defined. Flow simulation models characterized by limited spatial data of a key heterogeneity do not always represent the reservoir dynamics for water movement. In this paper, an efficient and rapid workflow is presented to estimate the recovery performance of an existing vertical-well, pattern-based waterflood recovery design using knowledge management and reservoir engineering in a collaborative manner. The knowledge management tool is used to gather production data and calculate pattern-based recoveries and injection volumes by defining pattern boundaries and allocating annual well injection/production volumes in a systematic manner. Classical reservoir engineering forecasting methods, namely, a combination of oil cut versus cumulative recovery performance curves, and decline curve analyses are applied to forecast the performance of the waterflood pattern of interest. The methodology is first applied to a synthetic reservoir model, and then to data from a real field developed by an inverted 9-spot recovery design. Extrapolating established trends of oil cut vs. recovery for each pattern for both the synthetic and real cases quantified future performance assessments. Time can also be attached to the performance by introducing liquid rate constraints. Forecasts based on real data highlighted the optimistic nature of the dated full-field simulation history match and provided a more realistic forecast for business planning. Forecasting using both constant and declining liquid rates differentiated the impact of deteriorating reservoir pressure and oil-cut trends on individual pattern oil rate forecasts thus defining current efficiency of each pattern. The methodology as a result turned into a simple yet powerful forecasting workflow that can be used by any asset team. This study is a very good example of how knowledge management tools can be used to increase the capabilities of classical forecasting methods in reservoir engineering.
Thermodynamically-Consistent Modeling of Adsorption in Liquid-Rich Shales
Authors: Rajput Vaibhav , Ertekin Turgay
Published: June 2014

Reservoir simulation and material balance techniques require accurate estimation of fluid storage and transportation mechanisms. In dry-gas shale reservoirs, it is widely acknowledged that gas adsorption is one of the most important storage mechanisms, and that it accounts for close to 45% of initial gas storage. In case of liquid-rich shales however, typically, adsorption is not considered as a storage mechanism. This paper proposes a method to estimate fluid adsorption from liquid phase in shale reservoirs. The proposed adsorption modeling formalism is based on the thermodynamically-consistent Ideal Adsorbed Solution (IAS) theory. The main development in this work is that adsorption from liquid phase can be calculated from its unsaturated vapor phase at the limiting saturation condition. Once the composition of this unsaturated phase is determined, the use of IAS theory would result in the amount and composition of the adsorbed phase being calculated.

Initial results suggest that, given a liquid phase mixture, typically about 5-13% of the fluid is adsorbed. This indicates that a significant amount of the liquid mixture initially exists in the form of adsorbed phase. However, the amount of each component in the adsorbed form is strongly dependent upon the total adsorption capacity of the particular shale, the amount of adsorbent present, as well as the adsorption affinity exhibited by the shale towards each component. Negligence of accounting for adsorption from liquid phase would result in erroneous calculation of total recoverable reserves from a particular liquid-rich field. This would also affect the enhanced recovery calculations, as thermodynamics would play an important role in the sorption of hydrocarbon components. This paper presents a direct and thermodynamically-consistent method of calculating the amount and composition of the adsorbed phase from liquid-rich shale reservoirs.
A Method for Pinpointing the Location of High Permeability Channels
Authors: Wu Hao , Najem Noha , Ershaghi Iraj
Published: June 2014

Many EOR processes fail because of the existence of unaccounted high permeability channels or fractures. Given a field under waterflood, where downhole pressures in producers can be continuously measured via permanent downhole gauges (PDG), we present a workflow process for pinpointing of high permeability channels without much disturbance of the field operations. The methodology requires a systematic scheduling of variations in the injection levels at selected injectors. The purpose of this study was to investigate the accuracy of estimated heterogeneity trends from processing of downhole response data.

The field setting is first divided into a series of clusters. Ranking of estimated high permeabilities among the clusters is the basis for mapping and pinpointing the location of the high perm channels. We demonstrate how the proposed algorithm can be used to detect sub seismic high permeability channels that negatively affect sweep efficiency. It can further allow an estimation of regional values of effective total compressibilities related to fluid types and areas with limited pressure support. This offers an enabling tool in designing and forecasting of field pilots for processes requiring expensive injected fluid.
Anisotropic Model for Permeability Change in Coalbed Methane Wells
Authors: Moore Robert , Palmer Ian , Higgs Nigel
Published: June 2014

With depletion of coalbed methane (CBM) wells in the San Juan Basin, permeability rises by 10 to 100 times. Similar permeability increases are found in other CBM basins around the world. Models previously advanced to explain this behavior combine a compaction mechanism (which closes cleats) with matrix shrinkage (which opens cleats). In this paper, the original model (Palmer-Mansoori model) is extended to include the transversely isotropic elastic response found in vertically cleated coals. This new version of the model has been calibrated by laboratory measurements on San Juan Basin coal loaded under uniaxial-strain conditions to simulate reservoir depletion. The result is a predictive model characterized by two measured Young's moduli and three measured Poisson's ratios.

To our knowledge, a rigorous geomechanical analysis of anisotropic coal has not before been incorporated into efforts to match large permeability increases observed in the field. We have been able to match the permeability increases in CBM wells using rock and reservoir parameters that are viable and consistent with independent constraints. To illustrate the results, permeability increases with depletion from a few wells in one area of the San Juan basin have been matched by the new model. The new model should allow better forecasting of gas rates by reservoir simulators, as well as improved predictions of gas production in fields yet to be developed.

While there exist many models that seek to explain the huge permeability increases in coalbed methane wells, the significance of this logical extension to the Palmer-Mansoori model (i.e., the addition of coal anisotropy) is that it has the ability to predict permeability increases in wells in the field using measurable rock moduli and other quantities, thus reducing the need for empirically-derived field-matching parameters. Note that this new model confirms an empirical constant that was invoked in a previous version of the Palmer-Mansoori model to account for cleat anisotropy. The rigorous derivation, for anisotropic coal, of permeability increase during depletion provides a missing link (and a significant one) that will save modelers from invoking more esoteric (and unnecessary) factors to try to get a match to field data.
Corrosion Management - it's all gone holistic
Authors: Stokes Pat , Sandana Daniel , Jones Lee
Published: June 2014

To manage the integrity of assets operating beyond their design life proactive corrosion management is essential. Traditionally topsides process plant, subsea pipelines and onshore terminals have been subjected to individual corrosion management schemes. An holistic approach that brings the corrosion management of these individual components into an integrated Corrosion Management System (CMS) has been developed for a variety of ageing offshore assets.

The CMS comprises a Corrosion Control Scheme (CCS), a Topsides Risk Based Inspection (RBI) scheme, a Corrosion Risk Assessment (CRA) and a Pipeline Risk Assessment (PRA).

The objectives of this integrated CMS process are to: Proactively identify all corrosion threats and define related riskDefine mitigation controls as necessary and ensure implementationEnsure mitigation controls are effectiveEstablish and implement corrective action as necessary

The overall corrosion management strategy is implemented by the CCS for a specific production asset which identifies the corrosion threats. It establishes the control and mitigation procedures required to mitigate internal and external corrosion on topsides process plant, subsea pipelines and related subsea components. The degradation mechanisms, controls and mitigation procedures are mirrored in the other CMS components. The future inspection programme for topsides process plant is driven by the RBI, whilst the CRA and PRA drive the future inspection and monitoring regimes for subsea pipelines. Results from these components are fed back into any review and upgrade of the CCS.

A CMS has been developed and implemented that meets the following objectives: A transparent and auditable decision making processProactively identifies corrosion threats and defines related tasksDefines mitigation controls as necessary and manages implementationEnsures mitigation controls are effectiveDefines inspection and monitoring regimes to assess asset conditionEstablishes and implements corrective actions as necessaryAn integrated scheme such that changes in one component are mirrored in the others.
Inching Toward Complete Well Integrity Management
Authors: Kumar Sanjiv , Al-Atwi Mohammed A. , Al-Mulhim Abdulrahman K. , Al-Otaibi Mohammad A. , Al-Mulhim Mohammed S. , Bu Ali Ahmed T.
Published: June 2014

Well integrity management (WIM) is an art of managing the well to reduce risk applying technical, operational and organizational solutions. With maturing fields and the evolution of advanced technologies, the industry has significantly improved in terms of WIM, though the art is still to be mastered. Nevertheless, WIM over the years has evolved and to some extent has become reliable enough to provide high confidence to operators to safely operate and manage matured fields. In spite of all the WIM practices in place, failure does happen. The root cause of the failure is carefully studied and necessary changes in process/technique are incorporated to ensure that such reoccurrences are not repeated.

Well integrity management starts from the stage of designing a well and continues throughout the life cycle of a well. The risk management becomes intense and difficult as the well gets older. Investment in gathering valuable well data remains a key to mitigate from risk and to better anticipate potential failures. Classical approaches to WIM are mainly for detecting a failure. Now, there is a paradigm shift, thanks to advanced technology at our disposal, to go for a predictive approach in forecasting a problem before it happens.

This paper describes the evolution story of proactive WIM at Saudi Aramco with emphasis on the utilization of corrosion monitoring tools as a predictive approach. The results of such a methodology can predict many "to-be" failures and allow for the timely resolution of expected integrity related challenges. The paper also narrates one case study for an oil well-A from Saudi Aramco, which developed a failure. The study of the root cause of the failure and lesson learnt were applied in improving the risk mitigating technique, and so inching toward complete WIM.
Chemical Treatments Practices and Philosophies in Oilfields
Authors: Awan M. A. , Al-Khaledi S. M.
Published: June 2014

Application of chemical treatments has become an essential part of everyday oilfield operations, to achieve specific objectives, minimize production problems, reduce production costs and achieve product specifications. Also, many process equipment performance and reliability problems can be solved economically by proper selection and application of chemical treatment practices. For instance, the corrosion problems that can be solved by changing metallurgy, reducing velocity, changing process conditions, removing corrosives upstream, can credibly be prevented by using corrosion inhibitors.

With increasing oil production, rising water cuts, H2S related issues and increased effluent water injection & disposal, the oilfield operating conditions are becoming more stringent, entailing the projects to be engineered with higher projected life. Also, with growing HSE concerns and compliance with environmental regulations, application of varied chemical treatments have become inevitable. Projects have been undertaken for introducing new chemical treatments, bulk handling of production chemicals, installation of chemical injections and monitoring systems. This necessitates periodic assessment of the chemical treatment practices and philosophies, for selecting and effectively monitoring & controlling performance of the chemical treatments by adopting a systematic approach.

To this effect our Company has deployed a huge network of chemical treatments and management systems all over its fields, for protecting its facilities/equipment, improving their performance, achieving quality, etc., taking into consideration; the process equipment problems, addressing HSE concerns and effectiveness of chemicals, etc. By operating and adopting a systematic & structured approach the chemical treatment practices have demonstrated proven performance. Those practices are not only cost competitive, but often can be implemented on-stream without curtailing unit operations.
New generation of Sour Service Drill Pipe Allows Addressing Highly Sour Field Challenges
Authors: Flores Vincent , Rodrigues Ricardo , Thomazic Aurelie , Thebault Florian
Published: June 2014

With the increasing demand of gas worldwide, some highly sour oil and gas reservoirs have been explored in Russia, Middle East, China and North America. The development of such fields, which contain a high percentage of sour gas, represents significant technical challenges regarding drill pipe integrity and operations safety. Sour service drill pipe have long been used with tool joints and tubes meeting separate criteria for sour service as defined by several industry standards. This solution is still acceptable today for most of the current fields. However, the new challenges associated with the particularly sour fields require new highly engineered drill string solutions in order to increase the safety margin related to Sulfide Stress Cracking (SSC) failure risks, especially in the welded zones.

Drill Pipes are commonly produced by assembling pipe and tool joins through friction welding. The weld, as a result of this process, presents, nevertheless, some challenges for preserving SSC resistance due to some metallurgical factors such as heterogeneous microstructure, different chemical compositions between the tool joint and the pipe body and high hardness values close to the welded line. Hence a new drill pipe configuration has been developed including modified chemical composition and modified manufacturing process. These modifications allow for the improvement of mechanical properties performance and SSC resistance in the welded zone.
Use of Molecular Methods (Pyrosequencing) for Evaluating MIC Potential in Water Systems for Oil Production in the North Sea
Authors: Mand Jaspreet , Jack Thomas R. , Voordouw Gerrit , Hoffmann Heike
Published: June 2014

The application of molecular methods, like pyrosequencing of 16S rRNA genes, has now accelerated to the point where identification of microbial communities involved in microbiologically influenced corrosion (MIC) may become routine. We have used this technology to characterize samples obtained from North Sea oil-producing platforms.

Pigging solids were collected from a pipeline that carried a high water content, had a low velocity and cooled rapidly (mesophilic growth conditions), causing high corrosion rates to be expected. A second set of samples was obtained from a platform subjected to produced water reinjection (PWRI). The samples included produced water and PWRI water, a mixture of produced water and seawater. Historically, both locations showed high sulfate-reducing bacteria (SRB) numbers and the system was deemed to be under corrosion threat.

Sulfate concentrations were 2600 ppm in the PWRI water and 170 ppm in produced water, suggesting that sulfate reduction occurred. The pigging solids were found to have high counts of SRB, identified by pyrosequencing to be mostly Desulfovibrio. However, high fractions (13–50%) of sulfur-reducing bacteria (SuRB), of the order Desulfuromonadales were also found. Pyrosequencing indicated that produced water also had more SuRB (48%) than SRB (18%). The PWRI water had a high fraction of the sulfide-oxidizing bacterium (SOB) Arcobacter (25%).

The data suggest that mixing of produced water and oxygenated seawater gives rise to chemical and microbial (Arcobacter) oxidation of sulfide to sulfur, which is then reduced to sulfide by the SuRB using oil organics as electron donor. The predominance of SOB and SuRB indicates that sulfur is prevalent in the system, which indicates that MIC may be involved in this environment. Application of molecular methods greatly facilitates the collection of this information and is thus an important tool in assessing MIC threat.
The Use of Computational Fluid Dynamics to Troubleshoot Excessive Metal Loss in a Carbon Steel Flowline: A Case History
Authors: Marinou Eugenia , de Souza Valdir , Djayapertapa Lesmana , Watson Ken , Moor Craig , Chalmers Frances
Published: June 2014

Greater Kittiwake Area (GKA) well KA-15, while not a significant oil producer anymore, provides large amounts of hot produced water which assists the field's first stage separation process. Historically, there have been numerous records of significant metal loss in the carbon steel flowline, especially at bends and welds, attributed to the line's convoluted configuration, flow rates and associated potential for erosion-corrosion effects.

This paper outlines the investigation process and corresponding findings. For fluid velocity calculations, computational fluid dynamics (CFD) was employed to allow highly accurate determination of the fluid velocity profile as well as the magnitude of localised wall shear stress. This was so as to assess the efficiency of the applied corrosion inhibitor and to provide a means of well management to avoid exceeding erosional velocities. In addition, a thorough review of the input parameters used for the corrosion inhibitor selection was performed; this revealed that erroneous inputs and inadequate testing were used for laboratory qualification of the chemical, with detrimental consequences for the flowline's integrity.

The study eventually concluded that the original material selection for the flowline was not appropriate for at least the current operating conditions and chemical testing was performed on unverified assumptions. This highlights the importance of using accurate methodology to validate inputs and that of periodic in-depth system reviews to ensure that new field parameters are re-evaluated correctly.
Experiences of Polymer Flooding Projects at Shengli Oilfield
Authors: Gao Chang Hong
Published: June 2014

Shengli oil field, located in Northeast China, is one of the largest and oldest oilfields in China. The field production peaked in 1991 and the overall water cut has reached 95% in 2012. The decline in production and the increasing demand for fossil energy have motivated the Shengli Oil Field Company (SLOF) to seek feasible enhanced oil recovery (EOR) methods. Since 1992, more than 60 units at Shengli field have received injection of polymer or a combination of polymer and low-concentration surfactants. Partially hydrolyzed polyacrylamide (HPAM) and petroleum sulfonate were chosen for most polymer flood projects. Field cases demonstrated that polymer flood and surfactant-polymer flood could effectively increase oil rate, decrease water cut and improve oil recovery.

This paper reviews several unique field trials at Shengli oil field. The earlier polymer flood projects targeted relatively ideal reservoirs with low temperature and low water salinity. However the undergoing polymer flood projects and future projects have to face very challenging reservoir conditions. Loss of polymer viscosity and reservoir heterogeneity affect the success of polymer flood projects. Future research at SLOF will focus on developing more tolerant polymers and improving the flow of polymer in reservoirs.
Laboratory Investigation of Miscible CO2 WAG Injection Efficiency in Carbonate
Authors: Duchenne Sebastien , Puyou Gilles , Cordelier Philippe , Bourgeois Marcel , Hamon Gerald
Published: June 2014

Remaining oil saturation, trapped gas saturation, three-phase relative permeability and injectivity are among the many parameters that play a major role in miscible CO2 water-alternating-gas (WAG) injection efficiency. In this work, we present a series of coreflood experiments designed to assess these parameters and investigate the microscopic efficiency of CO2 WAG injection on carbonated reservoirs, far above minimum miscibility pressure (MMP).

Experiments were carried out on intermediate-wet carbonate cores, initially saturated with light oil from a Middle East field, at reservoir conditions. Production was monitored at both reservoir and laboratory conditions providing material balance of each phase and separating the production of flashed oil, condensate and gas. A full compositional analysis was performed on produced volumes using gas chromatography (GC) and liquid analysis of flashed oil and condensate. Differential pressure across the core was also monitored for relative permeability estimation. Finally, a dual energy X-Ray scanner was used to measure three phase in-situ saturations, cross check material balance results and ensure that laboratory artifacts (end effects) do not influence interpretation conclusions. Coreflood data was complemented with PVT experiments including CO2-oil phase behavior characterization through multiple contact test (MCT) and supercritical fluid extraction (SFE).

CO2 WAG injections showed great performance with faster and better recovery than pure CO2 injection. After several cycles of WAG injections, high levels of differential pressure across the core were reached due to a reduction in both water and gas relative permeabilities with injection cycles.
Conformance Control Treatments for Water and Chemical Flooding: Material Screening and Design
Authors: Glasbergen Gerard , Abu-Shiekah Issa , Balushi Sameer , Wunnik John van
Published: June 2014

Heterogeneities in the reservoir can result in poor sweep efficiency during water and chemical floods. In many cases the sweep efficiency is improved significantly when changing to polymer flood. However, in the presence of very high conductive features polymer by itself may not be sufficient and result in undesired polymer production. Diversion of the flow to oil saturated regions and minimization of polymer production is then desired. In the presence of cross-flow the best option is placing a (chemical) plug deep in the reservoir. Adding a second component to the injection polymer stream that can react with the polymer to form a cross-linked gel is then an effective solution. However controlled placement and triggering of the reaction is very challenging.

In this paper we will present the results of static bulk measurements and dynamic core flooding experiments that were performed to identify cross-linked polymer systems. The polymers in the system are the typical high molecular weight partially hydrolyzed polyacrylamide (HPAM) polymers used in polymer flooding projects. The experimental work is focused on understanding and controlling the gelation time to enable proper placement and triggering at any given distance from the injectors. Parameters of investigation included temperature, brine composition, polymer concentration and rock mineralogy. The main parameters affecting the gelation process and possible failure mechanisms were identified. For given conditions, retardation of gelation time varying from few days up to several months could be designed. The learning from the experimental results can be used for improved material selection and design for other chemical and water flooding.
Conformance Control Treatments for Water and Chemical Flooding: Opportunity and Risk Evaluation
Authors: Abu-Shiekah Issa , Glasbergen Gerard , Balushi Sameer , Wunnik John van
Published: June 2014

The volumetric sweep efficiency is an essential factor in the success of any water flooding or EOR project. Volumetric sweep efficiency (VSE) is controlled by the local reservoir geological settings, well patterns and completion design and production and injection strategies.

In this paper we present a numerical modeling methodology to quantify VSE for different well patterns and geological settings independent of fluid types and saturation. The impact of conformance control techniques on VSE is estimated and the results translated to ultimate oil recovery for different driving mechanisms through standard analytical approximations. The methodology is used to evaluate the impact of conformance control techniques during water and polymer flooding for medium to high viscous oil reservoir. The results show that unselective blocking of high permeable layers during water flooding of high viscous oil reservoirs can be counterproductive and narrows the scope of potential chemical EOR opportunities. Polymer-(like) flooding wherever applicable is found to be in itself a very efficient conformance technique to increase the overall sweep efficiency for geological heterogeneities. In general abnormal high conductive features and long induced fractures tend to lower the efficiency of water or chemical flooding and cause excessive water/chemicals production to the surface facilities. Near wellbore mechanical treatments are then effective to minimize polymer production and increase oil production of which examples from ongoing polymer project will be discussed.
A New Modeling Approach to MEOR calibrated by Bacterial Growth and Metabolite Curves
Authors: Büeltemeier Hagen , Alkan Hakan , Amro Moh'd
Published: June 2014

Currently there is no commercial reservoir simulator used to model the growth phase of microbial enhanced oil recovery (MEOR), due to process complexity and significant dependency on laboratory data. One of the work packages of the project "MEOR Studies" being conducted by Wintershall is dealing with the modeling of MEOR to allow the reservoir simulation of the planned pilot. The reaction kinetics option of STARS/CMG is applied as analogy to Monod equation, which is usually used to model bacteria lifetime. One reaction is applied for bacteria growth and metabolite generation, mainly using the stoichiometric coefficients, whereas a second reaction is used to simulate decay of used substances. The parameters are calibrated by matching batch experiments measuring optical density (OD) of an enriched culture consisting of various strains isolated from one of the screened Wintershall fields.

All components of MEOR are modeled as tracer in water and/or oil phases. The EOR effects are modeled as function of the produced metabolites. Using this concept following primary MEOR effects are successfully modeled: reduction of oil viscosity by generated CO2, IFT reduction by bio-surfactant and increase in water viscosity by bio-polymer. Furthermore, the adsorption option of STARS is used for modeling the selective plugging effect created by biomass.

The validation of the new MEOR modeling approach is performed by using the results of sandpacks and coreflood experiments. In homogeneous sandpacks the additional 5–9 % oil of OOIP due to IFT reduction and rheology change in displacing phase was successfully modeled.
Chemical EOR in Low Permeability Reservoirs
Authors: Delamaide Eric , Tabary Rene , Rousseau David
Published: June 2014

Low permeability reservoirs contain a significant and growing portion of the world oil reserves, but their exploitation is often associated with poor recovery even after waterflood. Miscible or immiscible gas injection is usually the first choice in terms of EOR methods but it is not always feasible for instance due to lack of adequate supply. In such cases chemical EOR is often considered.

In this paper we propose to examine the specific challenges of chemical EOR in low permeability reservoirs by reviewing the well documented chemical EOR field operations that were implemented in reservoirs ranging from conventional low permeability (around 100 mD) to so-called tight reservoirs (few mD). Shale plays where permeability is in the µD range and which only produce when simulated by hydraulic fractures are not considered in our investigation.

We show that what works at the lab scale in low permeability plugs cannot be automatically transposed to the field scale. In particular low permeability can lead to injectivity issues and uncontrolled fracturing due to near wellbore plugging or simply to the high pressures required to propagate the injected chemical over large distances. Another challenging aspect of chemical EOR in low permeability reservoirs is the high chemical adsorption due to important surface to volume ratio and specific mineralogy, as in the case of carbonates (fractured or not). Success and failures of chemical EOR pilots in such challenging reservoirs, including innovative approaches such as wettability alteration, are reviewed.

Overall, this review will provide the reader with an updated view of past and on-going developments in chemical EOR applied to low permeability reservoirs. It should help operators determine whether a given low permeability reservoir is eligible to such processes or not.
A Novel Method to Model Low Salinity Water Injection in Carbonate Oil Reservoirs
Authors: Al-Shalabi Emad W. , Sepehrnoori Kamy , Delshad Mojdeh , Pope Gary
Published: June 2014

There are few low salinity water injection models proposed for carbonate rocks mainly because of incomplete understanding of complex chemical interactions between rock-oil-brine. This paper describes a new empirical method to model the low salinity water injection (LSWI) effect on oil recovery from carbonate rocks, based on the history matching and validation of recently published corefloods. In this model, the changes in water and oil relative permeability curves, as well as residual oil saturation, due to the LSWI effect are considered. The proposed model is implemented in the UTCHEM simulator to match and predict the multiple cycles of low salinity experiments. The screening criteria for using the proposed LSWI model are addressed in the paper. The developed model and the simulation results give more insight into the oil production potential of future waterflood projects using a modified water composition for injection.
Longitudinal Heterogeneity Effects in Alkaline Surfactant Polymer Flooding Enhanced Oil Recovery
Authors: Shahri Hamid Ghafram , Liu Keyu , Clennell M. B. , Liu Jishan , McKinley Allan
Published: June 2014

This paper describes experimental work to study the impact of longitudinal heterogeneity of porous medium (in terms of permeability) on the efficiency of ASP flooding that has been practiced in Enhance Oil Recovery (EOR). EOR becomes increasingly important as the globally proved crude oil reserves are being depleted. Chemical flooding is one of the tools to increase recovery; however, is still an active area for integrated research as it involves geochemistry, pore structure, microemulsion, fluid flow and chemical transport in porous media.

This present study is based on the use of carefully designed heterogeneous sand packs and monitors the effect of heterogeneity on the enhanced oil recovery by ASP slug. Oil recovery measurements were made based on mass measurements.

Results include the chemical profiles and its relation to EOR. The results indicate that longitudinal heterogeneities can impact EOR and the flooding of ASP slug from lower-to-higher permeability transition can mitigate the heterogeneity influence on EOR. In this experimental investigation, an enhancement of 5% (Original Oil in Place) was found when the ASP flood goes from lower-to-higher permeability transition as compared to that from higher-to-lower permeability transition. This finding can be of great importance to operators interested in implementing ASP floods.
Maximising Steam Project Value in South Oman through Flexible Development Phasing and Integrated Reservoir Surveillance
Authors: Al-Hinai S. M. , Tromp J. P. , Al Manahali M. O. , Belghache A. , Koning M. , Rabaani A. O. , Al-Adawi R. S. , Brissenden S. J. , Duggan T. , Alwazeer A. , Qi Chen Z.
Published: June 2014

EOR is key to the longer term business performance of Petroleum Development Oman (PDO). The "A" Steam Project in Southern Oman is a large scale EOR project currently being executed by PDO. It comprises the re-development of the "A" West Field, which has a significant prior cold oil development history, and the new development of the nearby "A" East Field.

The heavy viscous oil in both fields is contained in high net-to-gross braided river, aeolian and alluvial fan sandstones of the Cambrian Haima Group. Both fields were discovered in the 1970's. The "A" West Field has lower oil viscosity and was first produced in 1976. "A" East oil is significantly more viscous than "A" West oil and was believed to be too viscous to be produced by cold production, so "A" East Field was not developed. By 2008, after some 30 years of cold oil production, an estimated 18% of the STOIIP had been recovered from "A" West and the water cut steadily increased to 95%.

A field study was initiated in 2008 to evaluate re-development options based on EOR technologies. The selected Phase I (re-)development concept comprised a steam flood with fifty 10-acre / 7-spot patterns in "A" West and initial cyclic steam soak (CSS) with 74 wells on a regularly spaced 92 × 92 m grid in "A" East, with conversion later to a 8 acre / 9 spot steam flood. The two sub-surface developments were to be managed as an integrated project with shared surface facilities and operations. The project received FID for Phase I in 2009 and this is currently being executed. After the successful testing of cold production in selected new "A" East wells, a change to the Phase I FDP was implemented with the decision to cold produce the 32 most crestal wells prior to CSS in "A" East.

To de-risk the project, the more complex "A" West Field is being re-developed in a phased manner. Following field trials, initial CSS is now used to improve the gross rate of poorly performing producers, which constitutes a change to the FDP. To investigate the economic benefits of alternative patterns in areas of the field where steam flooding efficiency appears to be low, injection has recently started in two patterns which will become 10 acre / 10 spot trials. Additionally seven 3.3 acre / 7 spot trial patterns are being drilled on the western edge of the 10 acre / 7 spot development area.

Advanced time-lapse surveillance data acquisition techniques – DTS, DAS 3DVSP and HT optical pressure gauges - are deployed to support WRM optimization of the Phase I development, and to prepare the Phase II field (re-)development plan for the down-flank areas.
Implementation of Enhanced oil Recovery Techniques in India: New Challenges and Technologies
Authors: Baskaran Vijai Kumar , Dani Kamal Chandra , Kumar Krishna Pavan , Urkude Ashish Manohar
Published: June 2014

India's crude oil reserves tend to be light and sweet, with specific gravity varying from 38° API in the offshore Mumbai High field to 32° API at other onshore basins. India produced roughly 880 thousand barrels per day (bbl/d) of total oil in 2009 from over 3,600 operating oil wells. Enhanced oil recovery (EOR) is a term applied to methods used for recovering oil from a petroleum reservoir beyond that recoverable by primary and secondary methods. Primary recovery normally refers to the production using the energy inherent in the reservoir from gas under pressure or a natural water drive. Secondary recovery refers to usually refers to injection of water or water flooding thus, enhance oil recovery is often synonymous with tertiary recovery. Four group of methods –thermal recovery, gas miscible recovery, chemical flooding and microbial flooding are included in this collection. Implemented EOR techniques in India include alkaline surfactant flooding (ASF) in Jhalora-Rajasthan, Kalol-Gujarat, and Ankleshwar-Gujarat, immiscible hydrocarbon water alternating gas injection (HC-WAG) in Gandhar fields- South Gujarat, in-situ combustion/air Injection and simultaneous water and gas injection (SWAG) in Mumbai High. Some of the EOR pilots on anvil are immiscible CO2, microbial in-situ stimulation, and paraffin control microbes in western onshore regions of India. The planned techniques include air injection in light oil in western offshore, immiscible flue gas in western onshore and immiscible CO2 in eastern onshore. The Indian government and other oil E&P organizations expects this geographical dependence to rise in light of limited prospects for domestic production and hence, interested in Enhanced oil recovery techniques.
A Systematic Study of the Polymer Visco-Elastic Effect on Residual Oil Saturation by Core Flooding
Authors: Vermolen E. C. , Haasterecht M. J. , Masalmeh S. K.
Published: June 2014

The decrease in the residual oil saturation by polymer flooding with a high visco-elasticity solution has been widely addressed in the past few years. The effect of the polymer solution visco-elasticity on the microscopic sweep efficiency was studied experimentally in a range of length scales, from micromodels through core floods to full field application. In most of the micromodel and core flooding experiments, a comparison was made between the effect of glycerol and polyacrylamide solutions on the oil recovery, because glycerol does not exhibit elastic behavior (only viscous), while polyacrylamide solutions do.

In this paper it is discussed that the use of glycerol in combination with brine and/or polymer solutions could yield erroneous results due to a very strong dependence of the glycerol viscosity on temperature and on mixing with water. Instead, in the current study a series of core floods was done in which several polymer solutions were injected with a wide spread in viscoelasticity but the same apparent viscosity to study the effect of visco-elasticity on oil recovery.

The main conclusion of the study is that for the crude oil of high viscosity (~300 cP), hardly any effect was observed of increasing visco-elasticity on the oil recovery, even when both viscosity and flow rate were increased up to 300 cP and 3 ft/day, respectively. However, for the low viscosity crude (~9 cP), extra oil was recovered upon increasing the viscosity and/or flow rate of the polymer of high elasticity. No extra oil was recovered when using polymers of low elasticity even when using similar viscosity and flow rate, which indicates that it is an effect of elasticity and not of viscous stripping of residual oil saturation.

Thus, this paper confirms that polymers of high elasticity can reduce the residual oil to water. However, since this effect was only observed by either increasing the polymer viscosity or injection rate, the main challenge for field application is injectivity of the polymer at such high viscosity or rate, therefore before embarking on field application an injectivity test is required.
Improving Ultimate Recovery of Tight Sour Oil Field by Miscible Gas Injection
Authors: Cobanoglu M. , Jabri A. , Mahruqi F. , Sarmiento O. Quintero , Linthorst S.
Published: June 2014

The reservoir in South Oman – discovered in 1989 – is a 400m thick, tight, micro-porous silicilyte slab encased in salt at a depth of 4000m. The field contains the unique Athel silicilyte formation, some 4 km below the surface and is fully encased in salt as a result of which the reservoir is over-pressured at 800 bars. The Athel formation is sub-divided into 7 zones based on GR and Neutron/Density behavior. All zones are expected to be in hydrostatic communication despite the very low vertical permeability and the intensive layering of the silicilyte.

The crestal area has average matrix porosity of 22%. The permeability of the reservoir is extremely low (typically 1 – 100 μD) due to the fact that the rock mainly consists of micro-crystalline silica with abundant micro-solution seams and concretions/cemented beds and numerous sealing faults and fractures. The oil in this field is very light, low viscosity and volatile (48° API, Pb=260 bar, H2S=1.5%, CO2=2.5%). The application of massive hydraulic fracturing (2-4 frac/per well) combined with the favorable oil properties and under-saturated nature of the oil has made economic primary depletion development possible in this low permeability reservoir with reasonable initial oil rates (100-600 m3/day). Current oil recovery factor is 4.2% and expected to reach 10% through continued primary depletion. In 2007, an assessment of potential EOR applications aimed at improving the UR of the field concluded that MGI (miscible gas injection) via hydraulically fractured wells in the crestal area of the field is feasible, once field pressure has sufficiently declined. PVT experiments have demonstrated that miscibility pressure using its own produced hydrocarbon gas is close to the bubblepoint pressure of 260 bar. Subsequently a phased development was defined, depletion followed by MGI. Pilot injection into 2 patterns (Phase 3A) in the crest of the reservoir, will start end-2014 followed by a 2nd phase of crestal MGI (Phase 3B) by 2022. A final stage could be extension of MGI to the full field. With the application of full field MGI, the recovery factor could reach 40%.

The key risks for MGI are identified as early gas breakthrough, poor sweep, and limited injectivity. The pilot injection phase is designed to prove the MGI concept as well as to address these risks. Learnings and data acquisition from the pilot injection phase are essential for a decision on the future expansion of MGI.

This paper presents a methodology to evaluate this tight sour oil field development including EOR assessment, pilot injection monitoring plans and assessment of over 40 fracced wells.