bluuebunny/crossref_metadata_2025_split huggingface dataset:
Oil and Gas Fields Offshore Egypt: History and Case Studies
Authors: Ellaithy W. F. , Raheem M. G. A. 
Published: December 2007

Abstract
Egypt is located at the north east of Africa where Gulf of Suez and the South East part of the Mediterranean represent the offshore Egypt. Economical development of oil and gas fields in the Gulf of Suez and the Mediterranean requires to maintain the offshore installation within the cost effective envelop by selecting the appropriate development facilities, performing the construction with minimum interruption of weather down time, and selecting the suitable installation marine spread.
This paper presents studies based on several cases past experience of pipelines installation, offshore structures fabrication and installation and sub sea developments of offshore Egypt. The paper presents the weather conditions profile all year round and demonstrates the good weather conditions in both the Gulf of Suez and in the Mediterranean. Seabed conditions and change in water depth contribute to the final selection of the oil and gas fields development outlines, to the equipment selection for the offshore installation and the support marine spread. Onshore support and maximization of prefabrication in the near by fabrication facilities is another contribution to achieve cost effective development.
This paper presents case studies in pipeline installations, and complex platforms fabrication and installation, as well as sub sea facilities construction. The paper will discuss different approaches for pipeline protection and stabilization. In addition, it presents a comparison for conventional heavy decks offshore installation and sub sea equipment.
Transversely Multifractured Horizontal Wells: A Recipe for Success
Authors: Demarchos A. S. , Porcu M. M. , Economides M. J. 
Published: December 2007

Abstract
While the hydraulic fracturing of vertical wells is perhaps the most widely used method for production/injection enhancement in the petroleum industry, the fracturing of horizontal wells has been used sparsely, mostly in the United States and the North Sea. Usually this involves either longitudinal fractures or treatments with no regard to the well orientation and fracture azimuth.
The systematic transverse fracturing of horizontal wells poses several challenges in design and optimization and in operations and execution. A multi-fracture design and a feasibility study are performed to identify candidates for both a technical and an economic success. We used a fractured vertical well as the basis of our calculations and we have determined the dimensionless PI as the means to evaluate the attractiveness of multiple transverse fractures intersecting a horizontal well.
In previous publications we have presented the Unified Fracture Design and how its adaptation by several companies and researchers led to major new successes. The drainage shape and flow regime in transversely fractured wells differs significantly from vertical wells. The Unified Fracture Design had to be adapted with shape factors to account for the differences. We are showing a series of designs using a range of sizes of fracture volumes, different proppant types and drainage sizes.
For treatment execution, traditional methods of perforating may increase the probability of failure. The types of reservoir which are candidates for these treatments such as multi-layered reservoirs will almost surely affect the fracture initiation, and, as usual, composite materials show higher mechanical resistances compared to homogeneous materials. A new abrasive jet cutting tool has now been designed and built specifically for this type of jobs.
In this paper we will present all the design and operational challenges that will be faced in such fracturing project, and make recommendations for successful treatments
Shear-Type Borehole Wall Shifts Induced During Lost Circulations
Authors: Iwashita D. , Morita N. , Tominaga M. 
Published: December 2007

Abstract
Three typical borehole wall shifts during lost circulations are studied and parameter studies are conducted for evaluating the magnitude of the shifts. Slant-crack induced around vertical wells during lost circulations.Parameters varied are the frac size/wellbore size, frac angle, borehole pressure and σH1,σH2,σV ratio.Borehole wall shifts induced during the drilling of normal, thrust, and strike-slip fault areas.Borehole wall shifts induced for an inclined well due to a fracture induced in perpendicular to the minimum in-situ stress.
Full-Field Parallel Simulation Model: A Unique Tool for Reservoir Management of the Greater Burgan Oil Field
Authors: Ambastha A. K. , Al-Matar D. , Ma E. , Kasischke B. 
Published: December 2007

Abstract
The Greater Burgan field in Kuwait is the largest clastic oil reservoir in the world. Reservoir simulation in this gigantic reservoir presents formidable challenges in any modeling effort. Its sheer size, complex geology, intricate surface facility network, 2,200 completions, and 58-years of production history with significant uncertainty represented a daunting task in history-match and prediction.
The quest began in 2002 with the creation of a 65-million cells’ geostatistical earth model. The full-field simulation model of 1.6-million cells consists of six major oil reservoirs (Wara, Mauddud, 3SU, 3SM, 3SL, and 4S) with 145 faults. These faults are major conduits allowing fluid migration between reservoirs. This paper describes the history-matching process used in detail along with the value that has been added through prediction cases run with this model to date.
A tiered history-matching approach was used based on field, gathering center (GC), GC-sand and key well-level observations. Also, a full-field net oil column thickness map was used for detailed saturation matching over the entire field. Fault parameters, kv/kh, and aquifer connections turned out to be important history-matching parameters in this exercise.
Prediction cases with this model were set up by automatically managing GC-level oil and water handling limits, field-level oil rate targets, facility upgrades, infill drilling schedule, treatment of selective and additional potential wells, and operational criteria for individual well shut-down. Automatic logic to manage all of these features caused a parallel CHEARS (an internal Chevron reservoir simulator) 50-year prediction case run-time to be around 2 days on the 16-CPU IBM Regatta machine using AIX5.1 operating system.
Today, it is regarded as the key corporate planning tool for strategic field development and secondary recovery assessment for the Greater Burgan field. This model has been used for Base case forecasting as well as artificial lift, additional 3SU infill drilling, and Wara pressure maintenance project (PMP) evaluations to date. Procedures used to set up these value-added cases will be discussed.
The systematic process used in this project for history-matching and prediction will be useful for all reservoir simulation exercises on large fields with a very long history.
First Laboratory Perforating Tests in Coal Show Lower-than-Expected Penetration
Authors: Snider P. M. , Walton I. C. , Skinner T. K. , Atwood D. C. , Grove B. M. , Graham C. 
Published: December 2007

Abstract
Worldwide Coal Bed Methane (CBM) resources are huge, estimated at 3,000 to 9,000 Tcf. The worldwide production from CBM is dominated by US production of 1.6 Bcf/year, where an estimated 20,000 wells are in production from CBM reservoirs. Wyoming's Powder River Basin (PRB) alone has 12,000 wells in production, with an estimated 50,000 more wells to be drilled in the next 10-15 years. The production rate from CBM reservoirs is low, perhaps 50-100 mcf/day. Various completion methods are being evaluated and new technologies are being developed with the aim of increasing production rates.
Considering this interest and activity level, there has been very little attention paid to the CBM completion fundamentals. Perforating is a critical part of this process, especially considering the PRB development migration from single-coal open-hole completions into multi-zone cased-hole completions Whereas the industry has substantial knowledge of perforating characteristics in sandstones and, to a lesser extent, carbonates, almost nothing is known about perforating in coal. Predictions of perforation characteristics, such as depth of penetration, are based on correlations developed for sandstones.
This paper will describe the first known laboratory-testing program to investigate shaped charge penetration in coal targets. We will describe mechanical properties of the coals tested, and penetration results for different shaped charges (of different designs), shot at various stress conditions. CT scan and cutaway imaging of the perforation tunnels will also be discussed. Tests were conducted under dry and saturated conditions.
The preliminary experiments reported here indicate that shaped charge penetration in coal is significantly less than expected, considering the target's density and strength. The authors will provide insight into what may be the reasons for these unexpected results and recommend a path forward for shaped charge testing, designs, predictive tools, and how to optimize CBM completions.
Application of Smart, Fractured Water Injection Technology in the Piltun-Astokhskoye Field, Sakhalin Island, Offshore Russia
Authors: van Nispen D. J. , Hunt J. , Hartwijk A. , Trofimov A. 
Published: December 2007

Abstract
This paper discusses the application of new technologies and surveillance requirements with particular reference to fractured waterflood developments, highlighting specific considerations for the Piltun-Astokhskoye field and the harsh and sensitive Far East Russian environment. Early results and lessons learned from fractured water injection in the Astokh area of the field are presented, as well as implications ans plans for the Piltun development.
Theoretical Analysis of Bottom Water Invasion at Oil Wells Due to Transverse Dispersion
Authors: Duan S. , Wojtanowicz A. K. 
Published: December 2007

Abstract
Inaccurate modeling of fluid flow near-wellbores is commonly recognized as shortcoming of numerical reservoir simulators. After water breaks through, the well's inflow involves two or three fluids flowing at velocity exponentially increasing with reducing distance to the well. Understanding of the oil/water inflow to wells and possible improvement of its simulation is the objective of this study.
Current commercial simulators disregard the effect of dispersion due to high flow velocity. They only consider effects of viscous and gravity forces, capillary pressure and sometimes Non-Darcy flow effects. We postulate that a process of transverse immiscible dispersion should be considered in evaluating the oil/water transition zone around a well and the production water cut. Transverse dispersion is a process of mixing two fluids in the direction perpendicular to the segregated flow of two phases. In the process, one phase enters the stream of another phase and contributes to the flow characters and the saturation distribution change. Away from the well where the flow velocity is low, the effect is small and overshadowed by the capillary pressure effect. It, however, may significantly increase as the two-phase flow is approaching well since the transverse dispersion coefficient is a function of velocity. Thus, at the well, transition zone size and distribution might be significantly affected by transverse dispersion resulting in water production larger than results of current simulators.
In this paper, an analytical model of transverse dispersion in porous media is derived and used to study various factors influencing the dispersion. The results show that radial distance and mechanical dispersion coefficient are essential to transverse dispersion. It also shows that transverse dispersion controls transition zone growth at the bottom of well's completion where vertical gradient of horizontal velocity is the largest – up to 0.25 ft/s-ft.
New Results Improve Fracture Cleanup Characterization and Damage Mitigation
Authors: Ayoub J. A. , Hutchins R. D. , Van der Bas F. , Cobianco S. , Emiliani C. N. , Glover M. , Marino S. , Nitters G. , Norman D. , Turk G. 
Published: December 2007

Abstract
It is well documented in the literature that hydraulic fracture treatments, although successful, often underperform: Frac and Pack completions exhibit positive skin values, and traditional hydraulic fracture completions show discrepancies between the placed propped length and the effective production fracture length. Ineffective fracture clean-up is often cited as a likely culprit.
This paper presents some of the results of an investigation of fracture clean-up mechanisms. This investigation was undertaken under a Joint Industry Project (JIP) active since the year 2002. The data discussed builds on the initial results published in early 2006, which indicated that the polymer concentrates only in the filter cake and that flow along the fracture encounters significant yield stress when the filter cake cumulative thickness dominates the width of the fracture.
The new results presented here demonstrate successful strategies that mitigate the effects of excessive filter cake thickness. Experimental data demonstrate that flow along the fracture would encounter lower yield stress when the breaker is delivered directly to the filter cake as opposed to randomly distributed. The data also indicate that a smaller breaker amount delivered directly into the filter cake is more effective at reducing the yield stress effects than a larger breaker amount delivered randomly in the slurry. Alternative breaker materials are explored and additional data are also presented to estimate the yield stress effect for fluid flow across the filter cake from the reservoir into the fracture.
Hydrate Inhibition of Subsea Jumpers During Shut-in
Authors: Cagney T. , Hare S. , Svedeman S. J. 
Published: December 2007

Abstract
Flow assurance plans typically call for flushing subsea well/manifold jumpers with methanol to displace and inhibit any water accumulated in the jumper and to prevent the formation of hydrate blockages during shutdown. This paper presents the results of experiments that were conducted to evaluate the effectiveness of methanol injection and gas purging on removing and inhibiting water in a jumper. Variables in the test program included different water cuts and gas volume fractions in the jumper, the methanol injection rate, gas purge flow rates, oil properties, and the jumper inclination angle.
The tests showed that methanol injection rates, over 88 gpm (20 m3/hr), were required to sweep all of the water out of the 6.0" (15.24 cm) diameter horizontal jumper, but even at lower rates, 22 gpm to 44 gpm (5 m3/hr to 10 m3/hr), large amounts of water were removed. Inclining the jumper at angles from horizontal (up to ±5°) reduced the amount of water remaining in the jumper at the end of a methanol flush. Even at relatively low methanol injection rates, most of the water could be removed from an inclined jumper. Gas purge rates with superficial velocities in excess of 30 ft/sec (9.1 m/sec) were required to sweep all of the water from a horizontal jumper. Inclining the jumper to −5° from horizontal (fluid flowing downhill) significantly increased the amount of liquid removed from the jumper compared to the horizontal orientation.
The test results will be used to determine the design parameters required to prevent hydrate formation in deepwater jumpers. They will help define field requirements for methanol pump size, pump power, umbilical size, methanol storage requirements, and aid in the development of effective hydrate prevention strategies while minimizing platform requirements for space, weight, and power.
Quantifying 3D Land Seismic Reliability and Value
Authors: Bickel J. E. , Gibson R. L. , McVay D. A. , Pickering S. , Waggoner J. 
Published: December 2007

Abstract
Seismic data provide important information for guiding reservoir development. Improvements in data quality hold the promise of improving performance even further. Yet, the value of these data, and decision making capability, must exceed its cost. Previous work has demonstrated value of information (VOI) methods to quantify the value of seismic data. In these examples, seismic accuracy is obtained via expert assessment instead of being based on geophysical quantities. In addition, the modeled seismic information is not representative of a quantity that would be observed in a true processed seismic image. Here we apply a more general VOI model that includes multiple targets, budgetary constraints, and, importantly, quantitative models relating post-stack seismic amplitudes and AVO parameters to the quantities of interest for reservoir characterization, such as porosity and reservoir thickness. In addition, by including estimated changes in data accuracy related to signal-to-noise ratio, the decision model can provide objective estimates of the ability of the seismic data to provide reliable measurements and its value. We demonstrate this methodology within the context of a west Texas 3D land survey. This example demonstrates that seismic information can be quite valuable and improvements in seismic technology can create significant value for E&P companies.
Characterization of a Shallow Horizontal Fracturing Treatment in Western Missouri
Authors: Britt L. K. , Dunn-Norman S. , Smith M. B. , Atekwana E. , Slater L. , Gupta A. , Numbere D. , Fontana J. V. , Viellenave J. H. , Pelger J. 
Published: December 2007

Abstract
Normally, the objective of hydraulic fracturing is to design and execute a fracture treatment that achieves the desired fracture dimensions (length & conductivity) to maximize a wells production rate and reserve recovery. Treatments are most typically applied in reservoirs with in-situ stresses that yield vertical fractures. Case studies of horizontal fractures and identification of the key parameters unique to horizontal fractures are uncommon, in part due to the fact that oil and gas reservoirs occur in relatively deep subsurface formations.
A research project, sponsored by the U.S. Department of Energy, was undertaken to demonstrate a development method for the significant heavy oil reserves that exist at ultra-shallow depth in the Pennsylvanian sands in Southwestern Missouri and Southeastern Kansas. The principal objective is to demonstrate an economically viable and sustainable method of producing the shallow heavy oil using a combination of microbial enhanced oil recovery (MEOR) treatments and horizontal fracturing in vertical wells. In this application, the purpose of hydraulic fracturing is to expose additional reservoir surface area for subsequent microbial injection. Once the hydrocarbons are contacted by the microbes, the horizontal fractures are to provide a conductive pathway back to the wellbore for the lower viscosity hydrocarbons to flow.
Two wells in the study area, Fauvergue 1 and 5, were cased, perforated, and hydraulically fracture stimulated. Analysis of the treatments with surface tiltmeters confirmed that horizontal fractures were created. Geomechanical studies conducted prior to fracturing confirmed that the Pennsylvanian sands are more competent and have a greater Young's Modulus than previously reported in the literature.
This paper provides documentation of the extensive laboratory study conducted to develop an understanding of the elastic properties of the Warner and Blue Jacket sandstones and shale, fracture fluid sensitivity, and embedment testing.
The paper also reports the horizontal fracture stimulation execution and pressure analysis. Surface tiltmeter data are reviewed with the hydraulic fracturing performance, to determine whether the treatment objectives were achieved.
Field Trials of a New Method for the Measurement of Formation Gas Using Pulsed-Neutron Instrumentation
Authors: Trcka D. , Gilchrist A. , Riley S. , Bruner M. , Esfandiari T. , Ly T. , Shearin D. , Patino T. , Murray H. , Potter J. , Rose R. , Chen J. , Olsen S. , Lovera O. , McCants D. , Berger A. , Ellsworth K. , Barolak G. , Martain R. , McFall A. , Guo P. 
Published: December 2007

Abstract
This paper presents new hardware and analytical methods for determining formation gas saturation behind casing using pulsed neutron instruments. Instrumentation, characterization, algorithms, and limitations are discussed, and log examples are presented that illustrate the application of the methods in limestone and sand/shale formations.
The Role of Oil Chemistry on the Cold Production of Heavy Oil
Authors: Tang G. -Q. , Temizel C. , Kovscek A. R. 
Published: December 2007

Abstract
Two aspects of cold production of heavy oil are pursued. First, prior experiments have reported that the evolution of the size of mobile gas bubbles exiting a sandpack correlates with recovery by solution gas drive. Generally, systems that exhibit effluent bubbles on the order of the size of pores tend to recover more oil, all other factors equal. To develop an understanding of why gas bubbles remain dispersed in some viscous oils, we have interpreted functional groups present at oil interfaces that may contribute to bubble stability. The readily measured properties include the acid number (mass of base needed to neutralize the oil) and the base number (mass of acid needed to neutralize the oil) as well as the asphaltene content. The acid number quantifies, for instance, carboxylic acid functional groups that are associated with interfacial properties including wettability and interfacial tension. Second, solution gas drive laboratory experiments using three different viscous crude oils are examined in light of acid/base number measurements. The crude oils include two heavy samples from Venezuela and a viscous Alaskan sample. The acid number correlates positively with foamy (i.e, bubbly) oil behavior. The last oil with the least acid number shows no foamy-oil behavior. Effluent gas bubbles are large (2000 to 5000 mm) virtually from the onset of gas flow. Recovery is about 20% of the OOIP. The first two oils display small effluent gas bubbles, low producing gas oil ratio, and slow pressure decline during two-phase, gas-oil flow. The experiments also reaffirm the role of other factors important to heavy-oil solution gas drive including the solution gas-oil ratio, oil viscosity, depletion rate, and initial water saturation.
Successful Hydraulic Fracturing Techniques in Horizontal Wells for Sandstone Formations in the Permian Basin
Authors: Roudakov Vladimir , Rohwer Craig 
Published: December 2007

Abstract
This work summarizes the successful field experience best practices in single-stage hydraulic fracturing of horizontal wells in eastern New Mexico. Horizontal wells are thought to be the solution to increase productivity in formations with low to moderate permeability, great anisotropy, and heterogeneity. While the horizontal wells may produce at an economic rate without stimulation, hydraulic fracturing treatment increases productivity significantly. Multiple-stage fracturing treatments are highly effective, but the cost and risk associated with this type of stimulation often make it unattractive.
This paper presents the summary of more then 20 single-stage treatments in low- to mid-permeability sandstone formations that were successfully completed for several operators. The original wells had cemented liners and employed limited-entry technique to distribute the fracture treatment. An analysis of the treatment techniques in conjunction with the completion methods is presented.
An attempt is made to create the adjustable model of the unified treatment for given conditions to ensure successful hydraulic fracturing of these laterals. Several conclusions are drawn from presented data and design recommendations are made. This paper suggests the critical points in the treatment design and outlines the scope of future research.
The successful techniques, treatments, and practices presented in this paper can be applied globally including application in the fields of western Siberia.