bluuebunny/crossref_metadata_2025_split huggingface dataset:
Modeling and Optimizing Oil and Gas Production and Gathering Systems: Cerro Fortunoso Field Case
Authors: Galliano G. , Degiorgis G.L. , Lopez M. , Fornes A. 
Published: December 2007

Abstract
Cerro Fortunoso is one of the main fields of YPF Mendoza Business Unit. Itcurrently produces more than 7,500 bbl fluid/d from a hundred wells, most of them on sucker rod pumping. The field is located 80 miles from the nearest town, near the Andes Mountains and the environment is quite hostile windy, cold and with frequent snowfalls). Besides the field is very near a National Park.
Produced fluids are usually a problem. The oil is heavy (14.7 API) and viscous (more than 3,000 cp at ambient conditions). It tends to form emulsions with production water and behaves as a non newtonian fluid below 120 F.
The produced gas contains about 95 % of CO2 and has been vented up to now. In late 1996 a decision was made to reinject the produced gas in order to maintain pressure and prevent environmental damage.
A small technical team used a complex network simulator to model both the current field oil gathering and the future gas reinjection systems. Although the model fitted experimental data successfully and proved to be a powerful design tool some limitations to the simulator were found.
Due to the fact that commercial simulators do not take into account non-newtonian performance. a parallel study was conducted to analyze the effect of this behavior on predicted pressure drop. The team concluded that although deviation was found to be slight, non- newtonian effect should be properly included on design calculations.
As the gas will be reinjected at field conditions near its critical point. thermodynamics becomes extremely important. Five different thermodynamic software packages were run to predict gas phase envelope. Important differences between some models were detected.
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Unstable EOR Displacements and Their Prediction Using the Karhunen-Loeve (K-L) Decomposition
Authors: Gharbi R.B. , Smaoui N. , Peters E.J. 
Published: December 2007

Abstract
The paper describes a novel approach to model unstable fluid displacements in porous media. The approach is based on the Karhunen-Loeve (K-L) decomposition which is able to predict the fluid distributions of miscible displacements inside a porous medium. Several first-contact miscible displacement experiments, each with different fluid properties, were conducted, and the fluid distributions inside the porous media were mapped at various times using nuclear magnetic resonance imaging (NMRI). The K-L decomposition is described to identify the coherent spatial structures from spatio-temporal patterns arising from these experiments. It was found that these complex spatiotemporal behavior can be successfully described by few dominant eigen functions. The technique is based on the diagonalization of the covariance or two-point correlation matrix. The K-L decomposition provides information for the successful prediction of Enhanced Oil Recovery (EOR) processes.
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Analysis of Capillary Pressure Effects on Well Tests in Solution Gas-Drive Reservoirs
Authors: Tellez-C. Guadalupe , Camacho-V. Rodolfo 
Published: December 2007

Abstract
The effect of capillary pressure on well test is investigated. Solution gas-drive, homogeneous and naturally fractured reservoirs are considered. A numerical simulator, with a Warren and Root formulation for the case of fractured reservoirs, is used to generate synthetic data.
For homogeneous reservoirs the procedures of Perrine-Martin and pseudo-pressure are evaluated under the presence of capillary pressure. As expected the influence of capillary pressure is more pronounced in buildup tests than in drawdown tests. A capillary pressure number is proposed to evaluate the importance of capillary forces over viscous forces in different regions in the reservoir.
For naturally fractured reservoirs, the effects of including capillary pressure in the fracture and matrix systems are investigated. It is observed that, under certain conditions, both drawdown and buildup tests show capillary pressure effects in different flow periods under transient conditions. Also, the influence of capillary pressure on the flow transfer between matrix and fracture is documented, observing that the oil flow rate per unit volume from the matrix to the fracture system is lower when capillary pressure is taken into account.
P. 421
An Instrumented Hydraulic Fracture Experiment in Coal
Authors: Jeffrey R.G. , Settari A. 
Published: December 2007

Abstract
A 28-meter thick composite coal mega seam, made up of coal and thin inter-seam tuff layers, was instrumented with piezometers installed in three monitoring wells around a central injection/production well. After characterization of the site by injection interference well testing and step-rate testing, two separate intervals in the mega seam were stimulated by hydraulic fracturing while the pressure response in the coal at the three monitoring wells was recorded. The minifrac and main treatment in the upper part of the mega seam produced a strong pressure response at one of the monitoring wells, allowing a calculation of fracture growth rate in the coal to be made directly from the observed response. The field fracturing data were supplemented by laboratory core testing, downhole video logging of the central borehole, and underground mapping of the hydraulic fracture geometry and coal structures when the coal mine workings advanced through the central well. The fracture treatment data, constrained by the mine back, propagation rate, and piezometer data, have been analyzed by numerical hydraulic fracture models to compare the model and observed pressure response and fracture geometry. One of the fracture models used is a design model intended for use in coalbed methane stimulation design and, as such, includes permeability and leakoff as a function of effective stress around the fracture and the effect of non-linear and non-elastic deformation of the coal on fracture width.
P. 43
Potential for Infill Drilling in a Naturally Fractured Tight Gas Sandstone Reservoir
Authors: Harstad H. , Teufel L.W. , Lorenz J.C. 
Published: December 2007

Abstract
Modeling of the Mesaverde Formation in the San Juan Basin, northwestern New Mexico, shows the importance of using realistic drainage patterns in a naturally fractured reservoir. Fractures not only enhance the overall porosity and permeability of these reservoirs, but fractures also create significant permeability anisotropy. Permeability anisotropy causes the drainage area around the wells to be elliptical. Directional permeability is best found with multiple well interference tests. Predicted potential for infill drilling depends on the modeling approach, because elliptical drainage creates more overlap and undrained sections than a more radial drainage in an isotropic permeability case. Modeling with permeability anisotropy increases the potential for infill drilling and identifies optimum locations for new infill wells.
This approach has been applied in the Mesaverde Formation to determine economic optimization of infill drilling in these reservoirs and demonstrates that field development based on elliptical drainage areas can lead to a reduction in drainage overlap of adjacent wells and prevent leaving undrained areas. From multiple well interference testing a strong permeability an isotropy was found. Reservoir simulations were performed in pilot areas of different fracture intensity to quantify the potential for infill drilling, reducing the well spacing from 320 to 160 acre. Simulation results indicate areas of effective drainage, the optimum locations for infill wells, and the additional recovery from infill wells.
P. 59
Optimizing Well Capacity in a Tight Carboniferous Reservoir
Authors: Luan G. , Steffan E.M. , Weber R. 
Published: December 2007

Abstract
The Husum/Schneeren gas field, situated to the Northwest of Hannover, Germany, was discovered in 1986 and is jointly operated by BEB Erdgas & Erdol GmbH and Preussag Energie GmbH. The field was put on stream in 1987 when economic production was proven with the well Husum Zl, and reached plateau production in 1994 with 6 wells completing the initial development (Husum Z1 and Z2, Schneeren-Ost Z1, Schneeren Z 1/ Z2, Schneeren-West Zl).
Husum/Schneeren is a wrench related pop-up structure, with a gas column of about 1 000 m (3 300 ft), located at a depth of 2 300 m TVSS (7 550 ft) beneath the Husum salt dome. The reservoir comprises tight Westfalian fluviatile sandstones with average porosities of 5 %, mean permeabilities of 10 D, and an initial reservoir pressure of 385 bar (5 500 psi). The productivity of the reservoir is due to the presence of natural fracture systems which relate to the position of the structure at the intersection of two major tectonic lineaments. During drilling operations mud losses occurred due to high overbalance at the top of the large gas column. In all the early wells, therefore, a cemented liner was set over the reservoir interval and perforated in the fractured zones. Due to the unpredictability of the contribution of individual fractures to the production, initial well capacity was limited to 10 000 m3Ih (8.5 Mscf/d). Only after additional perforations could the current capacity level of 30 000 m3Ih (25 Mscf/d) at WHFP of 140 bar (2000 psi) be reached.
For a recent development well (Husum Z3), the reservoir target was chosen along the northern, highly fractured flank of the structure. In order to reach a borehole length of at least 800 m (2 800 ft) without experiencing severe mud losses, the well was drilled slanted at 450 through the slightly depleted reservoir, and completed open hole with a predrilled liner. Well capacity was tested at 30 000 m3lh (25 Mscf/d) at a WHFP of 200 bar (2 900 psi), enabling this unconventional tight reservoir to be drained efficiently.
P. 83
Surface Tiltmeter Fracture Mapping Reaches New Depths - 10,000 Feet and Beyond?
Authors: Wright C.A. , Davis E.J. , Minner W.A. , Ward J.F. , Weijers L. , Schell E.J. , Hunter S.P. 
Published: December 2007

Abstract
Recent improvements in tilt measurement techniques have greatly enhanced the resolution of hydraulic fracture-induced tilts, resulting in both greater mapping precision and an increase in the maximum mapping depth achievable with a surface tiltmeter array. With a previous depth limitation of around 6,000 ft., surface tiltmeter mapping was limited to areas with relatively shallow production. Application is greatly broadened now with a depth range down to 10,000 ft. In addition to the expanded depth range, there has been a marked improvement in the fracture mapping resolution.
This paper begins with an overview of the tiltmeter fracture mapping concept, highlighting both the strengths of this technique and its limitations. Following that is a description of the technical advancements made over the last three years to allow fracture mapping at far greater depths. Finally, two brief case studies are presented to demonstrate fracture mapping at great depth, and also to provide insight on hydraulic fracture growth behavior in two different environments. As the case studies make clear, fracture growth is far more complex than is generally assumed. Better understanding of these complexities can lead to significantly enhanced fracture stimulation practices.
P. 135
Development of the Pekisko Dolomite in the Bigoray Field. Issues in Formation Damage Mechanisms, Drilling Fluid Selection and Well Stimulation
Authors: Warren Brent K. , Skea Ken , Johnson Stan , Smithinsky Steve , Lunan Brian 
Published: December 2007

Abstract
The Pekisko formation in the Bigoray field in central Alberta is an oil-bearing dual permeability/porosity dolomite. A portion of the reservoir has permeabilities in the range of 1-2 Darcy and porosities approaching 25-30% while the rest of the reservoir features 10-30 millidarcy average permeabilities, 8-12% porosities and low initial water saturation. It is suspected that both rock types contribute to the flow of oil.
Drilling of horizontal wells in the Pekisko formation offers technological challenges in terms of field development and formation impairment. Damage mechanisms for the two rock types are expected to be different yet need to be addressed in one drilling fluid system. Open hole completion/stimulation to repair any formation damage and the avoidance of underlying water adds to the drilling challenges.
This paper describes the results of laboratory formation damage studies to both identify damage mechanisms and evaluate which drilling fluid system to be used in the horizontal well section. The higher permeability/porosity dolomite core plugs were damaged by solids plugging while aqueous phase trapping and solids plugging were responsible for damage in the lower quality rock.
A total of eight horizontal wells have been drilled in the field as of December 1997. The horizontal wells were drilled with three types of drilling fluids: oil, oil-soluble resin and a carbonate bridging system containing an aqueous phase trap reduction agent. The horizontal wells drilled with the carbonate/aqueous phase trap drilling fluid system had better oil production and less water than the wells drilled with the other drilling fluids. Discussion will also focus on stimulation of those horizontal wells that were damaged in the drilling process.
P. 161
Reservoir and Completion Study Improves Results in the Deep Red Fork Formation
Authors: Burns R.A. , Poulson T.D. , Finch R.W. , Aud W.W. 
Published: December 2007

Abstract
Technical integration of past stimulation practices with the subsequent production responses provided the insight for optimizing completion and stimulation practices in the deep Red Fork play of the Southwest Canyon City field. This case history illustrates the methods used to characterize the reservoir properties and the effectiveness of prior completion approaches. Based on these evaluations, a customized completion and stimulation approach was developed that was specifically tailored to match the identified reservoir, producing, and fracturing characteristics. Coupled with real-time execution of fracture stimulation treatments, this optimized approach increased the average daily production by 71% while reducing completion costs approximately ﹩150,000 per well. Average cumulative production from the 5 wells after 300 days using the new approach has increased from 400 MMscf to 700 MMscf. This combination of increased production and lower completion costs has dramatically improved the economic return from the field.
P. 185
Underbalanced Drilling in the Williston Basin
Authors: Purvis D. L. , Smith D. D. 
Published: December 2007

Abstract
The value of underbalanced drilling of open hole completed wellbores to minimize formation damage has been well established.
Underbalanced drilling by design does not build a filter cake in the wellbore. During conventional drilling this filter cake acts as a protective barrier reducing damage to formation permeability from drill cuttings. When drilling extended reach horizontal wellbores drill cuttings are ground into fine powder by the rotating drillpipe. If the wellbore does not have a filter cake and becomes overbalanced, this powder is carried into the formation greatly reducing near wellbore permeability. For this reason, preplanning and on-site engineering are critical in maintaining an underbalanced condition. Coordination and communication between drilling, nitrogen injection and return fluid handling are critical. This paper outlines the steps required from initial preplanning through the completion of the horizontal section. Case histories and results are presented. Various techniques for achieving an underbalanced condition via gas injection are examined. Nitrogen injection via a parasite string is examined in detail. Pre-planning steps are presented along with potential pitfalls and how to avoid them. A computer model capable of calculating the downhole pressure and flow conditions while drilling is described. The effect on pressure resulting from changes in injection rate, gas rate, density, viscosity and return pressure is analyzed. A comparison of modeled vs. actual downhole pressures is made to verify the validity of the model.
Decline Analysis' Relationship to Relative Permeability in Secondary and Tertiary recover
Authors: Masoner L.O. 
Published: December 2007

Abstract
Oil production declines under two processes:
pressure depletion and decreasing oil relative permeability as the oil saturation declines.
The literature offers derivations of Arps' exponential and hyperbolic decline equations for pressure depletion decline; these derivations apply to single phase flow or solution gas drive recovery only. This paper proceeds to derive Arps' hyperbolic decline equation from the principles of relative permeability. The results indicate that hyperbolic decline rigorously applies for relative permeability dominated secondary and tertiary oil recovery processes. Arps' exponential and harmonic declines apply only under very special conditions. The results further emphasize that history matched decline constants apply only during the recovery process under which they were determined. A method of translating between field scale oil relative permeability curves and oil decline is provided. The physical basis for the decline exponent, b, for these processes is revealed along with expected value ranges.
P. 245
Multiple Trend Forecasting Accounts for field Constraints
Authors: Wilson Scott J. , Miller Mark R. , Frazer Lamont C. , Digert Scott A. 
Published: December 2007

Abstract
Traditional decline curve analysis relies on curve fitting the primary producing phase while assuming that the other producing streams need not be considered. Both the Arps and Modem decline models consider only one producing stream when forecasting future rates. Although single phase trending is appropriate in many cases, incorporating the other streams improves the overall forecast reliability, especially where field liquid gas-handling constraints are significant drivers in a well's production profile.
This paper documents the practice of mathematically combining multiple production trends to improve predictions of the future performance of the single primary phase. Two methods are described in detail which specifically account for mature waterflood performance and gas-handling constrained production. Several field examples show the improved forecasts available from these relatively simple models. Although these methods are slightly more complex than single-phase curve fitting, modern computer decline programs are easily capable of implementing the models described here.
P. 253
An Integrated Method for Optimizing Hydraulic Fracture Design for Tight Gas Wells
Authors: Rietman Noel D. 
Published: December 2007

Abstract
A fully integrated method for optimizing frac treatments for tight gas wells has been devised. It includes predicting the flow performance under three flow regimes, matching well performance to determine or confirm the kh drainage area, and achieved frac length, and calculating the optimum frac length by using derivative curves. The sensitivity of the optimum length to different variables can also be determined easily by this method. For the reservoir and cost conditions considered, the optimum frac length is the most sensitive to variations in porosity, frac cost and pay thickness, somewhat less sensitive to drainage area, initial pressure and water saturation, and much less sensitive to permeability.
P. 259
Applications of Pre-Frac Injection/Falloff Tests in fissured Reservoirs - Field Examples
Authors: Barree R.D. 
Published: December 2007

Abstract
A method has been developed, based on the pressure versus 6-function curve and its derivatives, to characterize the pressure dependent behavior of formations from injection fall off test data. Characteristic shapes of the derivative curves differentiate between various closure mechanisms including pressure dependent leakoff associated with fissure opening. The dominant closure mechanism has been found to influence the treating behavior of the formation and help define the optimum fracture treatment design for the interval. In this paper, field examples of each major type of closure mechanism are presented along with the fracture treating response observed. The impact of natural fractures on production and injection will also be discussed.

Introduction
This paper is an extension of work originally presented at the SPE Annual Conference and Exhibition in 1996. The previous paper described the expected pressure falloff response of the 6-function and its derivatives, for pressure dependent leakoff and other factors affecting rate of fracture closure. The derivative response was predicted using the GOHFER fracture design simulator. This work adds to our understanding of pressure falloff behavior through the acquisition and analysis of extensive field data examples.
In the pioneering work by Nolte in 1979, fracture pressure decline analysis was proposed as a key to successful fracture stimulation treatment design. The method proposed was to inject a small fluid volume at constant rate and analyze the pressure decline to determine the fluid efficiency and pad volume requirement for achieving the desired fracture length. This technology appeared to offer a key to improved stimulation design.
By 1985 it was realized that this method, while very successful in many instances, did not generally identity wells which would be very difficult to hydraulically fracture. Many screenouts occurred which were not predicted by the existing pressure falloff analysis techniques. One possible cause of the noted failures was suspected to be pressure dependent leakoft, or fluid loss which increases with treating pressure.
Single and Multi-Well Modeling of a Tight Gas Sand in the Denver-Julesburg Basin, Colorado
Authors: Boone Lynn E. , Moore H. David , Birmingham Thomas J. , Delaney Jeffery C. 
Published: December 2007

Abstract
Fully-compositional, dual-porosity simulation models were constructed for the Codell Sandstone of the Wattenberg field in the Denver-Julesburg Basin, Colorado. The objective of this work was to develop simulation models which could accurately forecast reservoir behavior under various development scenarios. Characterization of the Codell formation is difficult due to heterogeneities in depositional and diagenetic fabric. Discontinuous higher-permeability layers, dispersed within a compact low-permeability matrix of the reservoir, requires connection to the wellbore through hydraulically induced fractures. Initially, a singe-well model was constructed to study the reservoir flow behavior in detail.
This model was used to develop a dual-porosity characterization representative of the reservoir within the drainage area of an individual well. The results of these simulations were then incorporated in a multi-well model used to investigate various development scenarios for several areas of the field. The reservoir descriptions in these models were derived from available log, core, PVT, and well test data. A fully-compositional fluid description was used to facilitate representation of significant changes in fluid properties across the field. Faults potentially affecting flow within the reservoir were identified during detailed geologic mapping.
P. 289