bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Pressure-Dependence Ratio: A Bottomhole Treating Pressure Diagnostic Tool for Hydraulic Fracturing in Tight, Naturally Fractured Reservoirs
Authors: Johnson Raymond L. , Dunn Kevin P. , Hopkins Chris W. , Conway Michael W. 
Published: December 2007

Abstract
As we continue to develop the processes of hydraulic fracturing in tight, naturally fractured, reservoirs, so continues our development of more effective bottomhole treating pressure (BHTP) diagnostics. New diagnostic techniques need to reflect the physical processes and give insight to potential damage mechanisms prevalent during hydraulic fracture treatments in these complex reservoirs. In this paper, we provide a thorough evaluation of BHTP trends observed during fracturing treatments performed in the Barnett Shale, a naturally fractured shale reservoir. From this evaluation, we are able to propose a new, more effective tool that can be combined with other BHTP and fracturing diagnostic techniques. Further, this analytic technique is easily adaptable to the treatment of other tight, naturally fractured reservoirs to enhance design or on-site decisions.
Enhanced C/O Saturation Monitoring Aids Water Flood Management - Case Studies from the Gulf of Suez
Authors: Elshahawi Hani , Naguib Mohamed , Hasan Ahmed 
Published: December 2007

Abstract
As oil fields mature, progressively more effort is being devoted to diagnosing production and reservoir problems and to finding cost-effective solutions for those problems. One of the key inputs for any reservoir management scheme is the timely monitoring of behind-pipe fluid saturation profiles across the field. In the past, this was conventionally accomplished using tools and methods requiring known, non-varying and sufficiently high formation water salinities. In the cases of water flooding with fresh water, mixed water, and/or water of unknown salinity, these methods become useless. In such cases, cased-hole saturation monitoring may only be achieved using tools and methods independent of water salinity such as the carbon-oxygen (C/O) method.
Using the C/O techniques to compute water saturation offers many advantages over conventional techniques that depend on formation water salinity. These techniques relate directly to the volumes of oil and water in the formation, and the conversion of C/O ratio to oil saturation is based on a large database acquired in a wide range of formations and well bore environments. Recent enhancements to spectral processing and job execution have resulted in dramatic improvements in the effectiveness of C/O logs. These enhancements include improved elemental standards and the development of a full spectrum calibration to provide better tool-to-tool accuracy and precision in a wider range of porosities even in the presence of gas. The enhancements also include operational improvements such as combination with production logging tools and appropriate "time-stepping" of shut-in and flowing surveys.
Several Gulf of Suez fields have undergone water flooding with non-native waters and have thus presented formidable challenges to traditional cased hole saturation monitoring techniques. More recently, operators in the area have started employing enhanced C/O techniques with great success. Enhanced C/O methods are now routinely used to effectively detect unswept hydrocarbons and to track fluid contact movements in water-flooded reservoirs. This paper discusses several case studies from the Gulf of Suez that clearly demonstrate the efficacy and economic benefits of the enhanced C/O methods.
East Javagas Pipeline Liquid Condensation Study Using Dynamic Multiphase Flow Simulator
Authors: Putra Satya A. 
Published: December 2007

Abstract
East Java Gas Pipeline is part of natural gas system in East Java that connects gas source at Pagerungan Island to Natural Gas Markets in East Java. The pipeline stretch about 420 km from the Pagerungan island to Gresik. It consists of 350 km sub-sea pipeline and about 70 km on shore pipeline. It delivers 350 MMSCFD gas to, natural gas consumers such as: power generation, fertilizer plant, and city gas. This paper will describe a simulation study on the pipeline. The objective of this study is to evaluate the pipeline hydrodynamic performance using a dynamic pipeline simulation model. The simulation will be used for the prediction of the amount of liquid that is trapped in pipeline, evaluation of current pipeline flow condition, for the assurance of the pipeline integrity. Pipeline dynamic model was developed by application of OLGA unsteady state multi phase flow. The model will be used to simulate the flow condition in East Java Gas Pipeline, such as: liquid condensation in pipe, scenario of changing gas properties during flow, pigging, and other flow dynamic scenarios. For the validation study of the model, pipeline operation data have been collected. Data that represent various operation condition or cases considered in the study are gathered, and will be compared with the simulation.
Effective Well Planning and Stimulation Improves Economics of Horizontal Wells in a Low-Permeability West Texas Carbonate
Authors: Willett Ronald M. , Borgen Ken L. , McDaniel B. W. , Michie Earl 
Published: December 2007

Abstract
When an operator is planning to drill a horizontal completion in a lower-permeability carbonate or sandstone reservoir, one of the prime well-design considerations is cost containment. Unfortunately, many operators use decision-making processes that are inappropriately weighted toward cost reduction and insufficiently or incompletely weighted toward incorporating completion processes that will ensure adequate producing rates. As a result, the ultimate hydrocarbon recoveries that were used in the economic justification of the program may not be achieved.
This paper presents a case study of a multiyear horizontal completion project in west Texas that was very successful in exposing the "false economy" of not cementing casing in horizontal wells drilled in low-permeability reservoirs. Increasing initial well costs about 20 to 25% resulted in a 3- to 10-fold increase in economic returns. This project included wells drilled in the heart of the play, in one of the flank areas, and also in an "edge" portion of the field, with comparisons to openhole completions in each area. The project offers several guidelines that should be followed by almost any global application of horizontal completions in lower-permeability reservoirs.
Porosity-Permeability Relationships in Clay-bearing Fault Gouge
Authors: Crawford B.R. , Myers R.D. , Woronow A. , Faulkner D.R. , Rutter E.H. 
Published: December 2007

Abstract
We have performed a series of coupled deformation and permeability experiments on "synthetic" fault gouge to investigate the influence of "shaliness" on fluid flow properties. Biminerallic gouge layers were sheared between steel sliders under triaxial compression and permeability measured continuously using the pore pressure oscillation technique. Permeability was observed to range over six orders of magnitude depending on clay content and sliding. Measured porosity variations, post-test laser particle sizing and direct observation of thin-section microstructures allows development of a geometrical model for permeability evolution in fault gouge containing varying amounts of clay.

Introduction
Faults can serve as both seals to hydrocarbon accumulation and conduits for secondary hydrocarbon migration. Evaluation of hydrocarbon entrapment and production patterns in faulted reservoirs requires understanding of the nature and properties of the fault rock material. Fault rock properties impact fluid movement regardless of timescale. In basin analysis, hydrocarbon migration over geologic time is dominated by the capillary properties of the fault zone, however fault rock permeability controls fluid flow on the development/production timescale. Fault rock properties are conventionally incorporated in flow simulation using transmissibility multipliers, which adjust the effective permeability between model cell centers based on estimates of fault zone permeability and thickness1. Fault transmissibility is a key parameter on the production timescale as it impacts well planning, well test interpretation and reservoir simulation of potential development scenarios in faulted reservoirs.
Fault rock permeability is a function of the microfabric developed within the fault zone, which in turn reflects the deformation mechanism(s) operative under different conditions of faulting2. Grain scale deformation in siliciclastic hydrocarbon reservoirs is primarily via cataclasis, diffusive mass transfer or a combination of these processes, depending upon interaction between lithology (mineralogy, texture) and environment (stress level, temperature). Fault zones are typically highly heterogeneous and variable over short distances. Fault seal analysis thus involves assessment of the distribution of fault rock types over individual faults, and estimation of their associated properties3.
Prediction and Evaluation of Sanding and Casing Deformation in a GOM Shelf Well
Authors: Ispas I. , Bray R. A. , Palmer I. D. , Higgs N. G. 
Published: December 2007

Abstract
Sand production is an important well completion issue impacting well economics and possibly casing stability. This study compares predictions of sanding and casing deformation for a well in the GOM shelf, done prior to completion of the well to the results of a post-sanding event for this well. The sanding event was adequately predicted considering the uncertainty of the data input into the model. The casing deformation monitored by the post-sanding survey was also consistent with the prediction of helical buckling caused by depletion of fluids only when cavities of vertical extent greater than 7 ft exist (e.g. due to sand production) around the wellbore. This study supports the use of these predictive methods in well completion design.
Guidelines for the Design of Fracturing Treatments for Naturally Fractured Formations
Authors: van Batenburg Diederik W. , Hellman Tom J. 
Published: December 2007

AbstractNatural fractures are present in many oil and gas producing reservoirs and largely contribute to the productivity of those reservoirs. Natural fractures, however, also complicate drilling, completion, and/or work-over operations. Hydraulic fracturing treatments are particularly sensitive for the presence of natural fractures as the hydraulic pressure may open the natural fracture system as well as the induced fractures resulting in additional (unexpected) fluid leak-off and consequently early screen-outs.Recent advances in pressure decline analyses of injection tests have provided the industry with a tool to recognize the presence of natural fractures. However, guidelines on how to design a hydraulic fracturing treatment once the natural fractures have been identified are lacking. The paper presents analysis of hydraulic fracturing treatments in naturally fractured reservoirs conducted in Algeria and Southern North Sea. The treatments analyzed include treatments that were completed as designed as well as treatments in which as little as 10% of the designed proppant amount was placed. Guidelines are proposed based on the commonalties that were found in these analyses.
WAG Injection at the Statfjord Field, A Success Story
Authors: Crogh Nidia A. , Eide Karen , Morterud Siv E. 
Published: December 2007

Abstract
Water-alternating-gas (WAG) injection technology is extensively used to improve oil recovery by increasing the macroscopic and microscopic sweep efficiency. WAG injection was implemented as a supplement to water injection at the Statoil operated Statfjord Field in February 1997. The field was then well into its production decline with a recovery factor of 54% and 70% water cut.
This paper outlines details of the project from its conception with a pilot area, to implementation and field performance after 5 years of WAG injection. The WAG injection project in the Brent reservoirs includes 15 injection wells, and the WAG potential accounts for a large portion of the remaining oil reserves.
The Santos: A Case History Of Fractured Shale Development
Authors: Wilson M.J. 
Published: December 2007

Abstract
Production in the Santos Shale interval of the Belgian Anticline Field was discovered on Texaco's Westpet leases in June of 1976. This fractured shale production is characterized by moderate production is characterized by moderate initial flowing rates of oil and gas, steep declines and limited reserves.
In 1976, an initial package of nine wells was recompleted in the Santos Shale. This attempt at development was considered unsuccessful due to the fact that only two of the nine wells will achieve payout by the time production declines to the economic limit.
A second development program was begun in February of 1978 after an extensive study. The evaluation technique utilized all the available data from the relatively new Carbon-Oxygen log to the relatively old Driller's log. Mechanical condition of the recompletion candidates as well as reservoir size and possible depletion was considered. The workovers were designed to minimize cost while not sacrificing producibility.
To date, seven wells have been completed under the new program. Payout of the seven as a package, occurred in approximately four months; from the date of initiation of the work. Successful development of the limited reserves is continuing due to systematic engineering and economic evaluation.

Introduction
A case history of the successful development of the Santos, a fractured shale reservoir in the Belgian Anticline Field, is presented. The Belgian Anticline Field is located in the southwestern portion of the San Joaquin Valley in Kern portion of the San Joaquin Valley in Kern County, California. Refer to Figure No. 1. Currently there are 13 wells producing from the Santos Shale. The areal extent of the reservoir on Texaco's property is approximately 93 acres.

RESERVOIR CHARACTERISTICS

GEOLOGY
The Belgian Anticline structure is a tightly folded, highly faulted reservoir. The trapping mechanism in its multiple producing horizons is twofold, the producing horizons is twofold, the anticline itself and the faulting. It is not unusual to find gas trapped downdip of an oil well producing from the same strata. Some geologists believe that almost every well on the western end of the field is producing from a separate fault block. A producing from a separate fault block. A structural interpretation contoured on the base of the Santos is shown in Figure 2.
The Santos Shale, to date, is the shallowest of the producing formations in the Belgian Anticline Field and is early Miocene in age. It occurs at an average depth of 2400' v.s.s. and may extend as deep as 4200' v.s.s. Typical dual induction laterlog response is shown in Figure 3. No oil water contact has been established in this reservoir.

ROCK PROPERTIES
The Santos Shale is a typical California type shale section which is often described as dark-gray-brown silty shale that is crumbly with an odor of oil. Portions of the massive section are highly Portions of the massive section are highly fractured. The fractures have been noted on both sidewall core descriptions and conventional core descriptions.
Radon Transients in Vapor-Dominated Geothermal Reservoirs
Authors: Warren Gary J. , Kruger Paul 
Published: December 2007

Abstract
Measurements of radon concentration in geothermal fluids sampled under transient flow conditions can be used to infer reservoir characteristics. Under steady flow conditions, changes in radon concentration indicate changes in radon emanation, while changes during rapid flowrate transients indicate changes in emanation and/or transit time from emanation site to the wellhead. This paper reviews the results of several radon transient experiments conducted in the vapor-dominated geothermal steam fields at The Geysers in California and at Larderello in Italy. In these transient experiments, samples of wellhead steam were collected over periods following rapid changes in flowrate. The data are evaluated with current models of vapor-dominated reservoirs to relate the measured wellhead radon concentrations to the flowrate conditions during the transient tests. Results of four such transient experiments are reported.

Introduction
The isotope 3.83-day 222Rn, a naturally occurring radioactive gas formed from decay of radium in the lithosphere, serves as an internal tracer of geothermal fluids in producing geothermal reservoirs (Stoker and Kruger, 1975). In a closed geothermal reservoir, the 222Rn concentration will be in radioactive equilibrium with its parent radionuclide, 1600-yr 226Ra, distributed throughout the reservoir. Some of the radon enters the pore fluids of the host rock by recoil energy and diffusion (Andrews and Wood (1972). The equilibrium concentration of radon in pore fluid is determined by the 'emanating power', the ratio of radon escaping from the rock to the total radon produced by radium decay. The steady-state radon concentration in pore fluid thus depends on the radium concentration in the reservoir rock, the factors controlling the release of radon from the rock, and the properties of the fluids filling the pores. The more important reservoir properties are: porosity, pore size, type of cementing materials, rock density and pore fluid density.
The radon concentration in pore fluid can be estimated from the relationships given by d'Amore, et al., (1978) in which the concentration is inversely proportional to the fluid density,
(Equation 1)
where Cs is expressed in units of radioactivity per unit mass of fluid (e.g., nCi/kg). Because of the large difference in density between pressurized steam and water, equation (1) indicates that the radon concentration in steam filled reservoirs could be 50 times higher than liquid filled reservoirs at a reservoir pressure of 460 psia (Warren and Kruger, 1979). The range of expected concentrations, based on an observed mean radium concentration of about 1 nCi/kg, and an estimated mean emanating power of 10%, might vary from tens to hundreds of nanocuries 222 Rn per kilogram of pore fluid.
Ninian Field Concrete Gravity Platform
Authors: Parat J.L. , Maher D.R.H. 
Published: December 2007

Abstract
The Ninian Central Platform was built at Loch Kishorn by Howard-Doris for Chevron (UK) Ltd.
The paper discusses the design process together with the construction methods. Special emphasis is given to the maximum flexibility of the construction stages to optimise the overall construction duration by using various slipforms and extensive prefabrication. Emphasis is also given to the Kishorn prefabrication. Emphasis is also given to the Kishorn Construction Yard and Facilities and to versatility to place modules eccentrically on the deck owing to the high resources of differential ballasting.

Introduction
The Ninian Central Platform will form the main base for the drilling and production of oil from the Ninian Field in the northern North Sea. The platform was built for Chevron Petroleum (UK) Ltd. by Howard-Doris Ltd. at their construction yard in Loch Kishorn.
To build this platform, the largest concrete offshore structure so far constructed and the fourth designed by Howard-Doris, a new platform construction complex was designed and built by Howard-Doris on the northern shore of Loch Kishorn on the West Coast of Scotland.
The concrete gravity structure was built during the years 1975 to 1977.
After the deck mating by the end of November 1977, the placing of modules and hook up was carried out from December 1977 to April 1978.
The concrete gravity structure was successfully set in place on May 17, 1978, the displacement of the structure at towing being 600,000 t.

DESCRIPTION OF THE STRUCTURE
The structure stands on a base slab 140 metres diameter, its general external shape (see fig.) is cylindrical with a progressive stepped reduction in diameter from the base to the breakwater wall (diameter 45 metres) which rises from 75 metres to a level of 149 metres above the sea bed.
The deck structure and modules are supported by two concentric cylindrical walls. The outer of these walls, the breakwater wall, takes the majority of the vertical loading from the deck. Its large diameter provides the possibility of many support points over provides the possibility of many support points over a large area thus reducing the deck cantilever. The wall is a patented Jarlan perforated breakwater design.
P. 241
Use Of Reservoir Simulation Models In The Development Planning Of The Statfjord Field
Authors: McMichael Claude L. 
Published: December 2007

Abstract
This paper describes the application of reservoir simulation models in the development planning of Statfjord field. The techniques used in all completed Statfjord field studies are reviewed. The paper concentrates, however, on the geologic data, simulation methods, and results of the 1977 Full Field Development Study. This study is the largest and most comprehensive study presently completed. The studies which are currently underway are also reviewed briefly, but a comprehensive report of this work is beyond the scope of this paper.

INTRODUCTION
The Statfjord Field is located on the border between Norway and the United Kingdom about 200 km northwest of the city of Bergen. Figure 1 shows its location in relation to other North Sea fields. The largest part of the field lies within the Norwegian Blocks 33/9 and 33/12 but a significant portion extends into United Kingdom Block 211/24.
The field was discovered in March 1974 by the Statoil-Mobil Group. operators for the Norwegian license 037. with their first wildcat Well 33/12-1. The discovery well encountered the Brent sand at 2382 m with an oil/water contact at 2584 m subsea. This contact has since been confirmed and is used as the field oil/water contact in the Brent sand. The well was located near the structural crest and produced oil which was undersaturated by approximately 1500 psi at the pressure datum depth of 2469 m. No gas cap was found and from the well location it was concluded that none existed in the reservoir. This has since been confirmed by other wells.
The confirmation well, 33/9-1, was drilled early in 1974. It encountered the Brent Formation with a full oil column and confirmed the productivity of the sand. The second major reservoir, the Statfjord, was discovered by the third well, 33/12-2, which found a partial Brent formation at 2458 m and the Statfjord Sand at approximately 2680 m with a full productive column. The Statfjord Sand oil/water contact was established at 2803 m subsea using the highest known water in Well 33/9-1 and lowest known oil in Well 33/12-2. As in the case of the Brent Reservoir, no gas cap was observed. The reservoir crude from the Well 33/12-2 tests was undersaturated by over 2700 psi at the datum depth of 2701 m and it was therefore concluded that the reservoir had no gas cap.