bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Comparative Study on WAS, SWAS, and Solvent-Soak Scenarios Applied to Heavy-Oil Reservoirs Using Five-Spot Glass Micromodels
Authors: Farzaneh Seyed Amir , Dehghan Ali Akbar , Ghazanfari Mohammad H. , Kharrat Riyaz 
Published: June 2014

Summary
In this work, a series of solvent- and water-injection scenarios were conducted on horizontal five-spot glass micromodels that were saturated initially with heavy oil. Sandstone and limestone rock look-alike and network patterns with different pore structures were used in the experiments. The results show that the ultimate oil recovery of a water-alternating-solvent (WAS) scheme was greater than that of a simultaneously water-alternating-solvent (SWAS) scheme, and the efficiency of a solvent-soak scheme also offers a greater recovery. Likewise, the WAS scheme resulted in greater oil recovery when compared with continuous solvent injection (CSI), with the same amount of solvent consumption. Furthermore, some pore-scale phenomena, such as viscous fingering, diffusion of solvents into heavy oil, and localized entrapment of oil and solvent because of heterogeneity and/or water blockage, are also illustrated. The results of this work can be helpful for better understanding and verification of flow transport and pore-scale events during different solvent-based-injection scenarios in heavy-oil reservoirs.
Framework Increases Effectiveness of M&A Teams When Acquiring, Validating and Analyzing Information from Data Rooms
Authors: Harrison Bob 
Published: June 2014

Abstract
Data rooms are inevitable whenever companies desire to acquire or divest oil and gas assets. They can be physical, i.e. a secure room with data placed within it, or virtual, i.e. an online data archive that can be accessed via a secure web portal, or a combination of both. If the data room visit by the prospective buyer's Mergers and Acquisitions (M&A) team lacks the necessary forethought and planning, it may not achieve its objective and the potential deal may be delayed, or even not go ahead at all.
This paper presents a framework to enable quicker evaluation of potential investments, while ensuring due diligence is taken when auditing estimates of resources and reserves. The framework is created for M&A teams with a wide range of experience and expertise, from newcomers to those who have spent too many hours in them.
Examples of real-life data room situations are given to illustrate how the framework is implemented. Advice is given on what data are essential to acquire versus those that are nice to have, depending on what the prospective buyer wishes to achieve. The challenge of selecting the appropriate make-up of the M&A team is also addressed. The framework gives clear and concise advice on what team members should do before, during and after the data room visit. Prioritized data lists are provided for each M&A team member, specific to their technical discipline, and key investigative questions to ask the seller are suggested. Time-saving ideas are proposed that can speed up any valuation in order that prospective buyers can quickly assess opportunities.
Finally, the paper describes some pitfalls that are inherent in any oil and gas asset evaluation, but which may have been avoided if the framework had been followed.
Experimental Investigation of Bitumen Recovery From Fractured Carbonates Using Hot Solvents
Authors: Pathak Varun , Babadagli Tayfun , Edmunds Neil 
Published: June 2014

Summary
With the decrease in conventional oil and gas reserves throughout the world and an ever-increasing demand for fossil-fuel-based energy and resulting high oil prices, focus has been shifting to unconventional and heavy oil and bitumen. Grosmont carbonates in northern Alberta have been estimated to contain at least 300 billion bbl of heavy oil or bitumen. However, recovering this oil is extremely difficult because of the complexity associated with carbonate reservoirs in general (e.g., the Grosmont unit is known to possess a triple-porosity system of matrix, fractures, and vugs, on the basis of core studies). The second problem is the fluid itself, which is highly viscous bitumen that is immobile at reservoir conditions. To extract this bitumen from heterogeneous carbonate rock, both heat and dilution using solvents may be needed. This paper reports the results and analysis of hot-solvent experiments conducted on original Grosmont carbonate cores. Three experiments were conducted using propane and one using butane as solvent. After heating the entire system containing the core sample, solvent gas was injected. The rock was allowed to soak in the hot solvent for a long time. The experimental temperature and pressure were decided on the basis of the results of our earlier work that suggested they be slightly above the saturation line of the particular solvent. An attempt was made to keep the conditions close to the saturation conditions of the solvent being used to maximize the dilution and, hence, the recovery. The oil produced was analyzed for viscosity and asphaltene content. The results in terms of recovery, the degree of dilution, and upgrading achieved suggested that butane was a better solvent for this bitumen. Finally, the optimum conditions for operation of the hot-solvent process were verified for Grosmont carbonates.
3D Modeling of Multistage Hydraulic Fractures and Two-Way-Coupling Geomechanics/Fluid-Flow Simulation of a Horizontal Well in the Nikanassin Tight Gas Formation, Western Canada Sedimentary Basin
Authors: Gonzalez Laureano , Nasreldin Gaisoni , Rivero Jose , Welsh Pete , Aguilera Roberto 
Published: June 2014

Summary
Unconventional gas is stored in extensive areas known as basin-centered continuous-gas accumulations. Although the estimated worldwide figures differ significantly, the consensus among the studies relating to unconventional gas resources is that the volumes are gigantic. However, the low permeability in these types of reservoirs usually results in a very low recovery factor.
To help unlock these resources, this paper presents a new and more accurate way of simulating multistage hydraulic fracturing in horizontal wells in three dimensions by use of single- and dual-porosity reservoir models. In this approach, the geometry (not necessarily symmetric) and orientation of the multiple hydraulic fractures are driven by the prevailing stress state in the drainage volume of the horizontal well. Once the hydraulic-fracturing job is accurately modeled in three dimensions, two-way geomechanical coupling is used to history match the produced gas from a horizontal well drilled in the Nikanassin naturally fractured tight gas formation of the Western Canada Sedimentary Basin (WCSB).
Traditionally, the most widely used approaches have their roots in semianalytical calculations simplifying the fracturing system to a planar feature propagating symmetrically away from a line source of injection. In contrast, the computed results presented in this study show that the incorporation of geomechanical effects gives a more realistic representation of the orientation and geometry of hydraulic fractures. Reduction in permeability of the natural and hydraulic fractures because of pressure depletion results in more-realistic production predictions compared with the case in which geomechanical effects are ignored.
The telling conclusion, in light of the computed results, is that the field of hydraulic fracturing provides an object lesson in the need for coupled 3D geomechanical approaches. The method presented in this paper will help to improve gas rates and recoveries from reservoirs with permeability values in the nanodarcy scale.
Criticality Testing of Drilling-Fluid Solids-Control Equipment
Authors: Aase Bodil , Omland Tor Henry , Jensen Ellen Katrine , Vestbakke Anne Turid , Knudsen Bjarte Sivert , Haldorsen Frode , Nysted Arvid , Storslett Eystein Ove , Steinnes Iren , Eliassen Einar Knut , Enger Jørund , Lie Øyvind , Peikli Vegard 
Published: June 2014

Summary
Correct selection and use of solids-control equipment are essential in not only maintaining drilling fluid at its desired properties but also in avoiding the generation of unnecessary waste streams during drilling.
Since the early 1930s, the shale shaker has been the dominant device for primary-solids removal. Additional equipment (e.g., desilters, desanders, and centrifuges) was often used in the past to maintain proper solids control, but experience in recent years has demonstrated that, although dependent on correct operational procedures, several types of shale shakers have sufficient performance to act as the sole solids-control devices without the use of desanders and desilters.
Despite often being the only measure for solids removal, the selection of shale shakers, the screening, and the establishment of operational procedures are often based on biased information (Dahl et al. 2006). In addition, it has been recognized that methods and criteria for the verification of shale shakers have not been sufficiently qualified and standardized. To address this, a multidisciplinary verification test of various solids-control concepts has been conducted. The objective of the test has been to verify equipment performance in a standardized, onshore test facility related to Oil-mist and vapor emissionVentilation (to obtain a satisfactory working environment)Flow-handling capacity with various drilling fluidsLeakage rate (i.e., the volume of fluid bypassing the filtration screen)Lost-circulation-material featureNoise and vibration levelMaintenance and equipment robustnessFeature for running lost-circulation-material reclamation
The tests were all planned and run in close cooperation with the equipment suppliers to ensure test-objective alignment. Several findings were made throughout the test period that provided vital information for design improvements and increased the industry's competence with respect to solids control.
Impact of Completion Design on Fracture Complexity in Horizontal Shale Wells
Authors: Manchanda Ripudaman , Sharma Mukul M. 
Published: June 2014

Summary
A proppant-filled fracture induces mechanical stresses in the surrounding rock that cause a reduction in the horizontal-stress contrast and stress reorientation around the open fracture. A 3D geomechanical model is used to simulate the stress reorientation caused by open fractures and to generate horizontal-stress-contrast contour maps. The reduction in horizontal-stress contrast can lead to increased fracture complexity. This paper describes ways to increase fracture complexity by varying the completion design.
In this paper, we identify the impact of operator-controllable variables in a completion design on fracture complexity. This can lead to more-effective completion designs that improve well productivity, reservoir drainage, and, ultimately, the estimated ultimate recovery (EUR).
The possibility of greater fracture complexity and reduced/effective fracture spacing and, thus, a higher drainage area is demonstrated for the alternate fracturing sequence in comparison to the conventional fracturing sequence. The Young's-modulus value of the shale and the in-situ horizontal-stress contrast are shown to be significant factors controlling the extent of fracture complexity generated in a given reservoir. In addition, the effect of proppant mass injected per stage is also shown to significantly impact fracture complexity. We provide optimal ranges of fracture spacing and proppant volume for the various shale formations analyzed. The use of these guidelines should result in more fracture complexity than would otherwise be observed.
The results presented in the paper provide the operator with the knowledge to design completions and fracture treatments (proppant volume, fracture spacing, and sequencing) to maximize reservoir drainage and to increase EURs. This should lead to more-effective completion designs.
Review of California Waterflooding Operations
Authors: Van Wingen N. , Melkonian B.L. 
Published: June 2014

Abstract
This paper presents a statistical review of California waterflooding operations. Water flooding was first started in California in 1944; and, as of June 1, 1960, there were 55 active secondary recovery water-injection projects. In addition, there are 14 projects in which pressure is being maintained by water injection and 18 waste-water-disposal projects.
The number of floods has increased markedly since 1951 when the crude-oil demand began exceeding the supply. However, for varying reasons, 24 water-injection programs have been discontinued.
The majority of floods were started following careful preliminary engineering analyses. No serious difficulties appear to have been encountered as a result of either the relatively high oil viscosity or the rather large average zonal thickness.
No data are available to evaluate increased oil recoveries which may result from the water injection, but response has been described as "good" in 20 of the 55 secondary water floods.

Scope of Investigation
The present investigation is concerned primarily with secondary recovery operations, or those water-injection projects which were instigated at a time when reservoir pressures had declined to values substantially less than the original. Other water-injection projects, those undertaken with the intent of maintaining reservoir pressure relatively near to the original or those primarily instigated for the purpose of waste-water disposal, have not been considered in detail. Projects in these latter classifications are listed in Tables 1 and 2.

Current California Secondary Recovery Projects
As of June 1, 1960, there were 55 active secondary recovery projects in California. At that time, the secondary recovery projects encompassed a total of 322 injection wells, into which water currently is being injected at a rate of 497,895 B/D. Fig. 1 shows the number of active secondary recovery projects in the state by years since the inception of flooding in 1944. This same graph also shows California's total annual crude-oil production and the annual refinery utilization of crude oil. It is interesting to note the accelerated rate at which new projects were started after the crude-oil demand began to exceed the supply. Tables 4a and 4b summarize all available data pertaining to current, active, secondary recovery projects in California.
The Value of Assessing Uncertainty
Authors: McVay Duane A. , Dossary Mubarak N. 
Published: June 2014

SummaryDespite the perception of lucrative earnings in the petroleum industry, various authors have noted that industry performance is routinely less than expectations. For example, Brashear et al. (2001) noted that the average return was approximately 7% in the 1990s, despite the use of typical project-hurdle rates of at least 15%. The underperformance is generally attributed to poor project evaluation and selection because of chronic bias. Although other authors have investigated cognitive biases in oil-and-gas (O&G) project evaluation, there have been few quantitative studies of the impact of biases on economic performance. We suggest that incomplete investigation and the possible underestimation of the impact of biases in project evaluation and selection are at least partially responsible for the persistence of these biases.The objectives of our work were to determine quantitatively the value of assessing uncertainty or, alternatively, the cost of underestimating uncertainty. In this paper, we present a new framework for assessing the monetary impact of overconfidence bias and directional bias (i.e., optimism or pessimism) on portfolio performance. For moderate amounts of overconfidence and optimism, expected disappointment (ED) was 30 to 35% of estimated net present value (NPV) for the industry portfolios and optimization cases that we analyzed. Greater degrees of overconfidence and optimism resulted in EDs approaching 100% of estimated NPV. A comparison of modeling results with industry performance in the 1990s indicates that these greater degrees of overconfidence and optimism have been experienced in the industry.The value of reliably quantifying uncertainty is reducing or eliminating both ED (realizing an NPV is substantially less than estimated NPV) and expected decision error (EDE) (selecting the wrong projects). Because biases are usually related, mitigating one bias will often mitigate others in the process. ED and EDE can be reduced by focusing on the elimination of either overconfidence or optimism, although there is an advantage to focusing on overconfidence. The elimination of ED will improve overall industry performance to the extent that superior projects are available and that better quantification of uncertainty allows the identification of these superior projects.
Four-Fluid-Phase, Fully Implicit Simulation of Surfactant Flooding
Authors: Patacchini Leonardo , de Loubens Romain , Moncorgé Arthur , Trouillaud Adrien 
Published: June 2014

Summary
The Microemulsion phase behavior model based on oleic/aqueous/surfactant pseudophase equilibrium, commonly used in chemical-flooding simulators, is coupled to Gas/Oil/Water phase equilibrium in our new four-fluid-phase, fully implicit in-house research reservoir simulator (IHRRS) (Moncorgé et al. 2012). The method consists of splitting the equilibrium into two stages, in which all the components other than surfactant are equilibrated first—by use of a black-oil, K-value, or equation of state (EOS) model—and the resulting Gas, Oil, and Water phases are then lumped into pseudophases to be equilibrated by use of the Microemulsion model. This subdivision in stages is conceptual, and at each converged timestep the four phases (Gas, Oil, Water, and Microemulsion, when simultaneously present) will be in equilibrium with each other.
The fluid properties (such as densities, viscosities, and interfacial tensions) and rock/fluid properties (such as relative permeabilities) required in the transport equations are evaluated with models from well-known industrial or academic simulators. Surfactant flooding being usually implemented as a tertiary recovery mechanism, on fields for which complete models that we do not wish to modify already exist, particular care is devoted to ensuring continuity of the physics at the onset of surfactant injection.
Our code is first validated against a reference academic chemical-flooding simulator, on a 1D, three-fluid-phase (Oil/Water/Microemulsion) coreflood. Second, as application examples where it is necessary to account for four phases in equilibrium, we consider a scenario where the chemical flood is preceded by a vaporizing Gas drive, as well as a scenario where dissolved gas is released by the Oil during the flooding process. Some aspects of our implementation, such as numerical dispersion vs. timestep length and nonlinear convergence, are also discussed; in particular, we show that numerical performance is not degraded by the four-phase equilibrium.
Pore Pressure Modelling and Stress-Faulting-Regime Determination of the Montney Shale in the Western Canada Sedimentary Basin
Authors: Contreras Oscar , Hareland Geir , Aguilera Roberto 
Published: June 2014

Summary
This work establishes an effective approach to predict pore pressure in theoverpressured Montney shale and overburden from sonic logs by implementingnormal-trend and explicit methods. The cause of the overpressure condition inthe Montney is also addressed. These two methods were selected on the basis ofthe study carried out by Contreras et al. (2012) that worked successfully forpore pressure prediction under subpressured conditions in parts of the westernCanada sedimentary basin (WCSB). As a second objective, the stress-faultingregime was determined in the study area by use of stress polygons and data fromdiagnostic fracture-injection-test analysis as a quantification of the minimumhorizontal stress. This is of paramount importance because there is not ageneric theory explaining the stress-faulting regime for most of the westernregion of the WCSB. The Eaton method from sonic logs (Eaton 1975) and theBowers method (Bowers 1995) were implemented in two vertical wells drilledthrough the Montney shale. The first part of the analysis considered two normalcompaction trends, but unreasonable pressure profiles were obtained andrequired a revision on the depositional environment. It was found that for thestudy area, three normal compaction trends have to be considered. The Bowersmethod was initially implemented using both loading and unloading conditions inorder to establish a safe range of pore pressure to allow successful wellplans. It is concluded that undercompaction could be masked as the onlyoverpressure mechanism in the Montney shale in the study area. The formationexperiences an inverse faulting regime that will lead to the creation ofhorizontal hydraulic fractures. The Eaton method using three normal compactiontrends and an exponent equal to 0.9 works successfully in the study area. TheBowers method uses the loading and the unloading conditions, and the specificcorrelation parameters were found to be suitable for the study area and can beextrapolated to adjacent future production and exploratory wells.
Effect of Bank Size on Oil Recovery in the High-Pressure Gas-Driven LPG-Bank Process
Authors: Lacey J.W. , Faris J.E. , Brinkman F.H. 
Published: June 2014

Abstract
This paper presents an analysis of the high-pressure, gas-driven LPG-slug process, based on fluid flow tests in areal models. Two types of tests were made. One series was made in low-pressure models which permitted observation of fluid movement. Three completely miscible analog fluids were used. A second series of tests was made in high-pressure models using methane, propane and a light refined oil saturated with methane at room temperature and 1,550 psig. Under the test conditions of room temperature and a pressure level of 1,550 psig, the phase diagram for the fluids used is similar to those for many of the field systems where the process is considered for use. A method for using these laboratory data to calculate field performance of the process is outlined.
As a result of this work, it is concluded that small banks of LPG (5 per cent HV or less) are not effective in increasing oil recovery in horizontal reservoirs. Instead, where small banks are used, the driving gas quickly penetrates the LPG bank because of fingering and channeling; and from this point on, the process behaves essentially as an immiscible gas-injection project. The validity of this conclusion was substantiated by:laboratory studies of the effect of rate, model size and mobility ratio on miscible displacement in areal models; andcalculation of field recovery, which compared closely with actual field recovery.

Introduction
Field applications and pilot tests of the gas-driven, LPG-bank, oil-recovery process are on the increase. Most of these tests are employing small banks (2 to 5 per cent hydrocarbon volume) of LPG, which is miscible with both the driving gas and the oil in place, in an effort to attain an effective yet economical miscible displacement of oil by gas. The expectation of miscible displacement with small banks is based on the concepts that:lengths of solvent-oil mixed zones, measured during miscible displacements in long slim cores, are representative of those that will occur in the field; andareal sweep efficiencies measured in electrolytic model studies are applicable to miscible displacement in reservoirs.