bluuebunny/crossref_metadata_2025_split huggingface dataset:
Improving Well-Performance-Data Analysis in Laplace Space by Using Cubic Splines and Boundary Mirroring
Authors: Ahmadi M. , Gonzalez O. G. , Ozkan E. , Parsa S. E. 
Published: October 2012

Abstract
Despite unequivocal advantages of using sampled well-performance data in the Laplace transform domain, time-domain analysis of pressure and production data have been more popular lately. This is because of the unresolved problems in the transformation of sampled data to Laplace domain as opposed to the demonstrated success of the recent real-time deconvolution algorithms. However, the transformation of sampled data to Laplace domain has a broader range of applications than deconvolution and the limited success of the past approaches to transform tabulated data to Laplace domain, such as piece-wise linear approximations, is an algorithmic issue; not a fundamental defect. Specifically, an adequate algorithm to transform the piecewise-continuous sampled data into the Laplace space and an appropriate numerical Laplace inversion algorithm capable of processing the exponential contributions caused by the tabulated data are essential to exploit the potential of Laplace domain operations.
In this paper, we introduce a new algorithm which uses inverse mirroring at the points of discontinuity and adaptive cubic splines to approximate rate or pressure versus time data. This algorithm accurately transforms sampled data into Laplace space and eliminates the Numerical inversion instabilities at discontinuities or boundary points commonly encountered with the piece-wise linear approximations of the data. The approach does not require modifications of scattered and noisy data or extrapolations of the tabulated data beyond the end values.
Practical use of the algorithm presented in this paper has applications in a variety of Pressure Transient Analysis (PTA) and Rate Transient Analysis (RTA) problems. Our renewed interest in this procedure has arisen from the need to evaluate production performances of wells in unconventional reservoirs. With this approach, we could significantly reduce the complicating effects of rate variations or shut-ins encountered in well-performance data. Moreover, the approach has proven to be successful in dealing with the deconvolution of highly scattered and noisy data. To illustrate the applications, typical field examples, including shale-gas wells, are presented in the paper.
Mensa Field, Deepwater Gulf of Mexico (GOM) - Case Study
Authors: Razi Muhammad , Bilinski Peter 
Published: October 2012

Abstract
Mensa, Mississippi Canyon Block 731, is a deepwater GOM subsea Geo-pressured gas field, producing from an upper Miocene; proximal lobate turbidite sheet sand associated with a faulted four-way closure. Reservoir structure is a nearly flat, covering some 5000 acres at depths of 15200 to 15,800 feet subsea. Net pay is as high as 170ft, average porosity 30% and permeability up to 1 Darcy.
Mensa Field is connected to platform via a +60miles subsea flow line. The field came on production in 1997 and rates peaked at 300 MMSCF/D during early life, with current rates ~27 MMSCF/D. As of Dec 2011 the field had produced 850 BCF gas. The field is producing by a combination of gas expansion, moderate water drive and compaction. Original reservoir pressure was 10,100 psi declining to 7,100 psi. Mensa field indicate presence of three distinct and unique pressure trends have occurred during field life.
The early life trend is related to the original development wells. During this time period pressures fell sharply, performing as a (dominantly) depletion drive reservoir. The trend indicates presence of isolated compartment(s). After a few years of production pressures leveled off significantly. The shift from early life trend to mid life trend is sharp and distinct. It seems reservoir became in contact with (originally) isolated gas compartment(s) and aquifer. History match (Material Balance and Reservoir Simulation Models) is achieved by establishing communication between main tank and (originally) isolated gas and aquifer (by breaking barriers). The late life pressure trend (occurred in the last few years) indicate that aquifer influx has effectively blocked the main producing wells from a significant gas area and pressure support. Recent pressure recorded in watered out zone is stabilized at ~7,100 psi.
The depositional setting for the "I" gas sand appears to be a lobate fan system associated with a turbidite basin entry -point. Based upon well and seismic data it can be subdivided into two shingled lobate deposits, oriented northwest to southeast and referred to as the "Ia" and "Ib". Seismic loop architecture suggests that the aquifer may also be composed of shingled lobate deposits. The "Ia" is the younger deposit and covers the northern portion of the field. It is probably completely filled with gas and is either shaled or eroded out before reaching the assumed GWC structural level at 15,775ft SS. The older "Ib" covers the southern half of the field and has GWC. The lobes are high net to gross (&gt; 90%) but contain very thin shale and other low permeability layers sometimes correlative between wells. The low permeability rock was not a barrier to gas flow as proved by a 2006 well test that penetrated swept (wet) "Ib" sand in a low structural reservoir position. In contrast, the combination of shingled lobate geometries and the aforementioned poor quality rock layers have proven to be a significant baffle to both higher pressure aquifer support and to water influx.
Understanding "SRV": A Numerical Investigation of "Wet" vs. "Dry" Microseismicity during Hydraulic Fracturing
Authors: Nagel Neal B. , Garcia Xavier , Sanchez Nagel Marisela , Lee Byungtark 
Published: October 2012

Abstract
Effective monitoring of hydraulic fracturing stimulations is critical to their optimization, and the evaluation of field microseismic data is now commonly used in many of the active shale plays for this purpose. The concept of Stimulated Reservoir Volume (SRV), for example, is a common technique wherein the extent of the microseismic data is used to represent the size of the fluid drainage area for a fracture or well. A principal challenge with the interpretation of microseismic data - and its use to determine drainage area or some other metric for the success of the stimulation - is the understanding of the actual cause of the microseismicity itself. Basic geomechanics principles show that rock failure - the cause of microseismicity - is a result of changes in the in-situ effective stresses relative to a given rock strength. Effective stress - which is the stress acting on the rock matrix - may change either through a change in pore pressure (leading to ‘wet’ microseismicity) or through a change in the total stress (leading to ‘dry’ microseismicity). Dry microseismicity may occur well beyond the pressure field and be hydraulically disconnected from the wellbore. In this paper, we present the results of a numerical study of hydraulic fracturing-induced microseismicity using a discrete element code, where the mechanical behavior of the natural fractures is modeled explicitly, which allows for the quantitative evaluation of ‘wet’ versus ‘dry’ microseismicity.
Structural Controls on Vertical Growth of Hydraulic Fractures as Revealed Through Seismic Moment Tensor Inversion Analysis
Authors: Baig Adam M. , Urbancic Ted I. 
Published: October 2012

Abstract
Completion designs for hydraulic stimulation of shale-gas reservoirs frequently accounts for vertical growth of the treatment volume in the formation. Where vertical growth is expected, wells are drilled near the base of the reservoir optimizing the distribution of proppant upwards. Other treatments may seek to transport treatment fluid across a lithologic barrier, effectively trying to "treat two formations for the price of one." Vertical growth needs to occur under controlled conditions, undesirable growth leads to a potential creation of pathways for treatment fluids to leak out of formation, or worse pathways allowing undesirable fluids to flow into formation. In either case, this could lead to a loss in optimization for production. To better understand vertical growth characteristics of hydraulic treatment volumes, microseismic monitoring arrays deployed downhole just above the formation provide a good discriminant for vertical growth of events. Further characterization of this growth can be accomplished through Seismic Moment Tensor Inversion (SMTI), when a sufficient angular distribution of multiple downhole arrays detects the microseismicity. SMTI can distinguish the source type of the mechanisms (e.g. openings, closures, shear, etc.) and the orientations of the activated structures, allowing for a more complete picture of the failure process. In the example provided, different stages of stimulation in the Marcellus shale formation are examined in the context of varying degrees of vertical growth. When vertical growth occurs, as identified through SMTI analysis, it appears to be related to the activation of sub-vertical natural joints whereas for vertically confined stages the primary fracture set is subhorizontal suggesting delamination of fissile bedding planes is the dominant process. These differences, from stages in the same completion program, suggest that subtle background stress changes can result in very different behaviors. Full understanding of these mechanisms will lead to further optimization of these treatment programs to promote vertical growth to traverse structural barriers and retain containment of the treatment within zone.
Application and Evaluation of Eulerian-Granular Approach for Characterization of Sand Erosion in Multiphase Flows
Authors: Lu Yaojun , Agrawal Madhusuden 
Published: October 2012

Abstract
This paper presents a novel approach for characterizing erosion wear in multiphase flow systems; it is based on Eulerian- Granular theorem rather than the conventional Eulerian-Lagrangian methodology. The first step in the novel approach is to characterize multiphase distribution based on the multi-fluid concept, which treats both the carrying fluid and entrained particles as continuous phases. The second step is to quantify the impinging velocity of particles using the granular model, which introduces particle-particle interaction and turbulence modification to carrying fluids beyond the fluid-particle and particle-fluid coupling considered in the Eulerian-Lagrangian approach. The final step is to determine the erosion rate by applying more representative particle velocity into a selected erosion correlation. In comparison to the Eulerian-Lagrangian approach, the Eulerian-Granular approach is able provide more realistic prediction on erosion profile in full particle loading range due to the least assumptions.
Poroviscoelastic Modeling of Time-Dependent Wellbore Closure when Drilling Anisotropic Gas Shale and Oil Shale Reservoirs - Applications in the Haynesville Shale and the Colony Pilot Mine Shale
Authors: Hoang Son K. , Abousleiman Younane N. , Hemphill Terry 
Published: October 2012

Abstract
The creep and relaxation characteristics of gas and oil shale create unique challenges to the characterization, modeling, and production from these unconventional reservoirs. Notable problems include modeling of stress relaxation and stress inhomogeneity during reservoir deformation, wellbore closure during and after drilling, reduction of brittle hydraulic fracture initiation and growth, and closure of hydraulic fracture and proppant embedment after stimulation. Moreover, the mineral structure and composition in addition to the extremely fine lamination and depositional modes forming the thin beddings in gas and oil shale creates geomechanical transversely isotropic behavior observable from the nano scale to the macro scale and adds further complexity to these problems. In this study, the effects of shale rock viscoelasticity, induced pore pressure, and shale rock anisotropy on time-dependent wellbore deformation and contraction during and after drilling were investigated using a fully-coupled geomechanics (poromechanics) approach. The complex interplay between time-dependent rock deformation and pore fluid pressure buildup and diffusion processes was explicitly modeled within the realm of poroviscoelasticity. Studies on the Haynesville Shale and the Colony Pilot Mine Shale have also been carried out using material parameters determined from laboratory creep tests. It was found that the viscoelasticity of the rock matrix controls not only the final magnitude but also the rate of wellbore closure during and after drilling. Moreover, the transversely isotropic nature of the reservoir shale must be accounted for in the estimation of wellbore wall displacement. The common assumption of material isotropy for traditional reservoirs led to severe errors in the estimation of the magnitude as well as the rate of wellbore contraction.
Surfactant Enhanced Oil Recovery from Naturally Fractured Reservoirs
Authors: Lu Jun , Goudarzi Ali , Chen Peila , Kim Do Hoon , Britton Christopher , Delshad Mojdeh , Mohanty Kishore K. , Weerasooriya Upali P. , Pope Gary A. 
Published: October 2012

Abstract
Large volumes of oil remain in naturally fractured carbonate oil reservoirs and water floods are often very inefficient because many of these reservoirs are mixed-wet or oil-wet as well as extremely heterogeneous. Naturally fractured reservoirs are challenging targets for chemical flooding because they typically have a high permeability contrast between the fractures and the matrix with low to extremely low matrix permeability. In addition, some of the world's largest oil reservoirs are fractured carbonates with high reservoir temperature and high salinity formation brine and some of them also have low API gravity oils, which also increases the difficulty of recovering the oil. We have developed a stable surfactant that shows promising results even when all of these conditions are present at the same time. Both static and dynamic imbibition experiments were done using a fractured carbonate core. These results were interpreted using a mechanistic chemical reservoir simulator.
Effect of Nanoparticles on Flow Alteration during CO2 Injection
Authors: Aminzadeh B. , DiCarlo D. A. , Chung D. H. , Kianinejad A. , Bryant S. L. , Huh C. 
Published: October 2012

Abstract
Surface-treated nanoparticles have been shown to stabilize CO2-in-water foam by adhering to the surface of CO2 bubbles and preventing their coalescence. However, to bring the nanoparticles from the bulk phase to CO2/water interface requires an input of mechanical energy. Co-injection of CO2 and an aqueous dispersion of nanoparticles at high rates is known to provide sufficient energy. However, this co-injection is less favorable because of the operational constraint, i.e., injectivity reduction. Here, we show that beneficial effect of nanoparticles, manifested as improved sweep efficiency, occurs even at low shear rates in a drainage displacement.
We inject high-pressure liquid CO2 into sandstone cores initially saturated with brine containing suspended nanoparticles and compare the results with the case with no nanoparticle addition. The water saturation distribution was measured using CT scanning techniques. The results show that the nanoparticles increase sweep efficiency and reduce the gravity override compared to displacements without nanoparticles. The new mechanism described here provides a promising alternative for mobility control in CO2 floods.
Analysis of Hydraulic-Jet Lift System application on Wells in the North Region Assets, AIPRA and AIATG (Case study)
Authors: Granados J. , Mancilla S. F. 
Published: October 2012

Abstract
Hydraulic-Jet (HJ) lift system field tests were performed in wells of "Activo Integral Poza Rica-Altamira" (AIPRA) and "Activo Integral Aceite Terciario del Golfo" (AIATG) assets in North Region of "Petroleos Mexicanos-E&P" (PEP). Results are analyzed in this case study, which includes background, objectives and scope, overview on HJ theoretical frame, tests results, a brief technical and cost analysis, conclusions and recommendations.
Part of technological challenges in oil fields exploitation, are those associated to wells without own enough energy to flow from the bottom hole to the surface facilities. This condition occurs in most of the wells of AIPRA and AIATG assets, becoming Artificial Lift Systems (ALSs) a strategic issue essential to achieve production goals and mandatory topic subject to permanent analysis and evaluation.
Operative continuity during observed periods of the HJ tests, support technical feasibility for wells in AIPRA and AIATG, with low incidence of failure, rapid restarting of the system, as well as few associated workover; and consequently low delayed production because of these reasons. Furthermore, HJ potential to fulfill key advantages was observed, among them: feasibility and speed of running and retrieving without workover rig, in situ production measurement feasibility, low flow rates achievement feasibility, and, in AIATG case, capacity as a centralized system in multi-well locations. For these cases, these circumstances are considered as "breaking paradigms" for hydraulic lifting as a system only applicable to wells of relative high productivity. Achieved results support economic feasibility of the Hydraulic-Jet lift system in the two assets, even evident marginal profit for AIATG case, where reduce costs because encompasses integral systems for several wells in the same location is an option.
Based on previous experiences, it has been observed that, the more suppliers petroleum market incorporate, the more opportunities to lower costs come to pass until "real costs" are achieved. Hence, it is recommended to involve new suppliers as a strategy to promote competitiveness.
Compositional Controls on Mudrock Pore-Size Distribution: An Example from Niobrara Formation
Authors: Kuila U. , Prasad M. , Derkowski A. , McCarty D. K. 
Published: October 2012

Abstract
Speculation exists about the presence of micropore and mesopore networks either exclusively within the organic matter or as pore systems in the inorganic components. This study presents a comparison of pore-size distributions (PSD) in a set of fine grained rocks from the Niobrara Formation using a combination of meticulous, precise, and repeatable laboratory preparation and measurement techniques. The analyses were performed on aliquot samples of ground powders (&lt;0.4 mm) following rigorous procedures of homogenization and division (splitting) to obtain mineralogically and chemically equivalent portions for each analysis. The mesopore and micropore distribution was measured by conventional subcritical N2 gas-adsorption analysis at 77.3 K. These results, combined with quantitative mineral analysis by XRD and organic content and maturity measurements, indicate that the abundance of illite-smectite group clay controls the small scale pore features in the Niobrara Formation. The samples show a characteristic 3 nm pore-size distribution peak that correlates strongly with clay abundance, but not with organic content. The low thermal maturity of the organic matter (OM) further implies the lack of associated small pores. Instead, this non-porous OM hinders access to the fine mesopore structure of the clay aggregates.
The Development of Organic Porosity in the Woodford Shale Related To Thermal Maturity
Authors: Curtis M. E. , Cardott B. J. , Sondergeld C. H. , Rai C. S. 
Published: October 2012

Abstract
Since the discovery of pores in the organic matter of gas shales, the conventional thought has been that the pores formed as a result of hydrocarbon generation during the thermal maturation of the organic matter. However, thermal maturity alone may not be the only factor in determining the formation and preservation of pores in the organic matter. In this paper we report on a study of organic porosity in Woodford Shale samples with vitrinite reflectances ranging from 0.51% Ro to 6.36% Ro. Using focused ion beam (FIB) milling and scanning electron microscopy (SEM), it is observed that while the first appearance of porosity for the samples occurs by 1.23% Ro, there are anomalies. One anomaly is the complete lack of organic porosity in the 2.00% Ro sample. In addition, some samples with a vitrinite reflectance ≥ 1.23% Ro exhibit regions of porous organic matter adjacent to non-porous organic matter regions that are separated by a few microns Observations show that while some regions of porous organic matter appear protected by grains others appear stress-supporting. These observations have important consequences for using indicators such as thermal maturity in predicting the occurrence of pores in the organic matter of shales.
Ceramic Sand Screens for Sand Control in Unconsolidated Reservoirs: Application and Sand Retention Capabilities in the Maturing Oil Field, Gaiselberg, Austria
Authors: Wildhack S. , Lesniak C. , Müssig S. , Strahammer F. , Leitner M. 
Published: October 2012

Abstract
The oil production in Zistersdorf, Austria operated by the Rohölaufsuchungs AG (RAG) has a long history beginning with the first completion in 1937, and a variety of production technologies were applied. The reservoirs here are primarily of Sarmatian sand stones showing good compaction and permeability in lower zones but highly unconsolidated sands and serious sand production in upper formations.
The sands in these upper layers are poorly sorted, so it is difficult to realize sand control. In the past, sand production has been handled by metal wire wrap screens combined with gravel packing. Large amounts of finer particles, however, made it necessary to downsize the slot openings in order to protect pumps and jewelry. In consequence, the wells experienced an increase in pressure drop over the screens and the gravel packing, in some cases resulting into production losses of up to 50%.
With the newly developed stand-alone ceramic sand screens, this disadvantage could be eliminated, and sand control in the unconsolidated formations was successfully proven in the Gaiselberg 16 well.
This paper will present the design of the applied ceramic screen, its deployment underneath the downhole pump and the production data of Gaiselberg 16. The evaluation of productions rates, pressure drops and sand measurements will be discussed and compared with performed sand retention testing. The paper will give an interpretation of the sand retention mechanisms of the ceramic sand screen and its capability to assist the building up of a natural formed gravel pack.