bluuebunny/crossref_metadata_2025 huggingface dataset:
Energy Sources and Energy Intensity for the Twenty-First Century
Authors: Economides M. J. , Demarchos A. S. , Saputelli L.
Published: December 2007

A country's wealth is closely related to its energy consumption. For example, the United States, the richest nation, with a per capita income of about $34,000 is also one of the highest consumers of energy with an annual per capita consumption of about 355 million British thermal units (MMBTU). Energy consumption is the most discernible national characteristic that separates rich from poor countries. The correlation between per capita energy consumption and per capita income among all nations is clear. However, the energy use in other developed countries is also a function of their geography, the makeup of those countries and even the cultural preferences of their citizens.

Throughout the last two centuries, energy consumption in the creation of wealth and the form of primary energy sources, have not been constant. The process has been dynamic and technology has played a considerable role in the changing of the status of many countries, most notably Japan. Efficiencies developed elsewhere are adopted by other countries and lead to an increase in wealth. Globalization of the economy will certainly aid this process in the future.

Energy consumption and heightened demand worldwide may prove perhaps the most formidable international challenge of the twenty first century. It must be emphasized, though, that political events such as the September 11, 2001 terrorist attacks and associated implications may have considerable impact, affecting both the sources of energy and the type of energy. We have not attempted to predict these effects in this paper. As early as 2010, at current energy growth, chronic energy shortages are likely to emerge which may evolve into a serious energy crunch. The most logical way to prevent this situation is to transition rapidly to natural gas and, eventually, to hydrogen.

In this paper, natural gas is viewed as the compelling next fuel of choice and as the necessary stepping-stone towards hydrogen. Also offered here are production, consumption and transition forecasts.
Successful Integration of Sparsely Distributed Core and Welltest Derived Permeability Data in a Viable Model of a Giant Carbonate Reservoir
Authors: Al-Afaleg Nabeel I , Al-Garni Saad , Rahmeh BasemAhmed , Al-Towailib Asaad
Published: December 2007

This paper presents a successful integration of sparsely distributed permeability data including core-derived permeability and welltest-derived permeability into a viable geocellular model of 3.96 million cells for a giant carbonate reservoir. The resulting model required minimum permeability modification to achieve a 40-year history match. Fracture intensity trend was derived by carefully comparing the curvature of the structure, detailed matrix permeability, and welltest-derived permeability. This approach, although intuitive, allows for a better and realistic characterization of this large reservoir in the absence of seismic and other fracture identification tools like image logs while preserving vertical and lateral variation in permeability. Moreover, the paper presents statistical analysis of core-derived permeability illustrating lateral variation of permeability distribution.
New Resin Technology Improves Proppant Flowback Control in HP/HT Environments
Authors: Anderson Robert W. , Johnson Daryl E. , Diep Tom
Published: December 2007

This paper will focus on a new resin technology that improves proppant flowback control under extreme conditions. The combination of dual phase flow and pressure drops in high rate gas wells has made proppant flowback a significant problem. These conditions must be addressed to maximize well productivity and minimize production costs. Moreover, the problems associated with cyclic stress effects can further hamper well production and tax any technology controlling proppant flowback. The most commonly applied proppant flowback control technology is the use of curable resin coated proppant (CRCP) either entirely or as a tail-in for hydraulic fracturing treatments. CRCPs have an established history in the consolidation of proppant packs under defined conditions of time, temperature, and closure stress.

Improvements in CRCP performance have been facilitated by use of a new resin system through chemical and process changes. These changes have enhanced resin bond strength (RBS) characteristics commonly measured as unconfined compressive strength (UCS). Data shows RBS is anything but the dominant trait in preventing proppant flowback. This is most evident when the proppant pack is subjected to a large pressure drop, Non-Darcy multi-phase flow, temperature, and cyclic stress. Further associated effects are prolonged pumping time and elevated temperature exposure during CRCP placement. The CRCP placed under these conditions is subjected to elevated temperatures while the proppant is transported into the fracture and before fracture closure. CRCP performance testing in the laboratory can accurately depict these effects.

A new resin technology is presented that is specifically designed to withstand the aforementioned conditions. The performance benefits are documented by rigorous laboratory testing (under simulated downhole conditions) and case history data from stimulation treatments performed on deep, high flow rate gas wells.
A Comparison of Interventionless Packer Setting Techniques and Enhanced Functionality Considerations
Authors: King James G.
Published: December 2007

Eliminating intervention during well completion reduces operating expense and risk. In deepwater, horizontal and extended-reach applications, interventionless actuation systems for setting completion tools are reducing well intervention and completion time and associated costs without compromising reliability or safety. This paper details the operation of three commercially successful technologies that permit interventionless actuation. This author outlines the selection process for determining the correct technology for a given application.
New C/O Methodology Applied for Reservoir Monitoring in Atypical Casing Completion and Complex Lithology: A Case Study
Authors: Padilha Solon Thomaz , Escobar Elena , Ramónez Miguel , Solórzano Efrén
Published: December 2007

Carbon Oxygen ratio (C/O) logging has been used in the oilfield for a long time as a solution to determine oil and water saturations independent of the formation water salinity. The traditional Sw computation methodologies rely on the use of the tool under standard and uniform completions, and are based either on a data base characterization or on deterministic models. These techniques fail when the casing size, along the logging interval, is variable, or when the tool characterization is not available for unusual casing sizes.

Uncertainties are also encountered in complex lithologies, particularly in the presence of carbonates, due to deposition or diagenesis. In this case, it becomes difficult to compute the correct carbon content of the rock to correct the final volume of oil estimated.

This paper describes a case study with a very atypical completion including downhole sensors as part of the casing, and the presence of a variable carbonate volume in the reservoir rock matrix. It is part of a project to define the evolution of a water flooding between two nearby wells, one the injector and the other the monitoring well. Here, a new computation methodology to calculate the volume of oil using the openhole computed Sw, as a reference, and different time lapse C/O logging passes to define the change in volume of oil in the reservoir during the water injection, is presented. This variation (ΔVuoi), applied to the openhole Sw, enables the computation of precise saturation results, where it is possible to observe the quantitative change in fluid volumes in depth over a period of approximately six months in spite of the nonstandard completion type and complex lithology.
Equipment Strategy Development for Down-hole Tubulars
Authors: Russ P. R.
Published: December 2007

A risk based inspection and equipment strategy program was developed for mature down-hole tubulars in Bass Strait oil and gas wells. This paper outlines the major features of the program including identifying components, describing degradation mechanisms, assigning a credible failure scenario, defining the probability and consequence of failure, development of strategies to mitigate "unacceptable" risk and finally assigning a mitigated risk.

The strategy development is applicable for caliper and proactive work-over candidate selection, work-over rig plans, reservoir depletion strategies, downhole corrosion management and platform life end plans.

A key feature of strategies is determining the probability and consequence of tubing failure. The consequence of failure determined in these reviews is based on financial criteria given that Safety, Health and Environment (SHE) risk is low due to completion design. The basis for obtaining these will be described. Corrosion rate and failure prediction are based on Bass Strait field data and are used in determining probability. Consequence is based on reservoir remaining reserves and when combined with probability is plotted on a risk matrix. A multi-functional team develops strategies to mitigate risks that are determined to be "unacceptable". Strategies include "do nothing", inhibition, patch tubing, coil tubing, work-over, proactive work-over, utilise corrosion resistant alloy, caliper and continue to monitor. The team measures success by determining the resultant mitigated risk.

The paper describes a process that enhances the tubing life cycle management process. Using this tool cost saving can be obtained through proactive preventative programs and utilisation of failure prediction to provide for improved planning and budget management.
Hydraulic Fracturing in a Deep, Naturally Fractured Volcanic Rock in Japan – Design Considerations and Execution Results
Authors: Weijers L. , Griffin L. G. , Sugiyama H. , Shimamoto T. , Takada S. , Chong K. K. , Terracina J. M. , McDaniel B. W. , Wright C. A.
Published: December 2007

In the summer of 2001, the first multi-stage completion in a deep, hot, and naturally fractured volcanic rock of the Minami-Nagaoka Field, Niigata Prefecture, Japan, was successfully completed using six propped fracture treatment stages.

Successful proppant placement in the northern part of the Minami-Nagaoka Field in Japan has proved to be extremely difficult in the past1-2. During two propped fracture treatments pumped more than a decade ago, treatments failed miserably with only about 20% of the designed proppant placed before job termination due to premature screen-outs. Post-frac evaluation showed extremely high levels of net pressure of order 4000 psi prior to pumping any proppant – indicating that proppant placement problems were mainly occurred due to simultaneous propagation of very narrow multiple hydraulic fractures. Detailed pressure build-up tests and production data analysis confirmed the diagnosis of narrow multiple hydraulic fractures, which resulted in extremely poor propped fracture conductivity and non-economic gas production.

As successful development of the northern part of the Minami-Nagaoka reservoir could significantly impact Japan's domestic natural gas production, another attempt at propped fracture stimulation was justified. In the summer of 2001, the first multi-stage completion in a deep, hot, and naturally fractured volcanic rock of the Minami-Nagaoka Field was successfully completed using six propped fracture treatment stages. The new treatments in Minami-Nagaoka focused on the ability to mitigate the adverse effects of multiple hydraulic fracture propagation and the accompanying severe near-wellbore fracture tortuosity. A major equipment mobilization was required for this treatment to be possible as part of this concerted effort. Many unconventional changes, including completion changes to obtain highest possible injection rates to enhance proppant placement, aggressive proppant slug strategy, extensive fluid testing, real-time fracture treatment analysis, careful perforation placement, quality control, extreme overbalance perforating, and use of small-grained proppant, resulted in successful stimulation and favorable production response. This paper discusses all these design changes in detail, and provides final results regarding the fracture geometries obtained and post-fracture production response.
Guntong – Key Challenges and Issues in the Management of a Large Complex Oil Field
Authors: Wan-Mohamad Wan-Nawawi , Coyne Patrick L. , Hinton Paul V. , Razalli Razmahwata M.
Published: December 2007

The Guntong field is currently the largest waterflood field and a major oil producer in Peninsula Malaysia. The field and its development are highly complex, resulting in various challenges in the areas of reservoir description, reservoir management, and facilities optimization.

This paper showcases key challenges and the evolution of the field depletion plan as the complexities were identified and better defined. Based on actual performance, and updated geoscience and reservoir engineering studies, various changes to the original depletion plan are being implemented even after 17 years of production. The changes range from a revision in waterflood operating pressure strategy, to innovative facilities optimization, and the more expensive workovers and infill drilling,. Effective teamwork by multi disciplinary team members also played a major role in transforming the challenges into opportunities. The implemented changes to-date have successfully increased production and reserves.
Practical Experiences of Improvement Oil Recovery for Weizhou 11-4 Bottom Water Oilfield in South China Sea
Authors: Hongyin Zheng , Pengxiao Sun
Published: December 2007

The Weizhou 11-4 oilfield is located in the North Gulf Basin of South China Sea. This oilfield is the massive sandstone reservoir of marine sedimental formation with strong bottom water drive. Its structure is a simple and complete drape anticline without faults. The reservoir geological properties are fairly good. The average porosity is 22%, and the average permeability is 945md. The thickness of sand body is from 30m to 50m. There is a stable distribution of the tight sandstone layer to be developed just above the oil-water contact in the entire oil-bearing area.

During the oil producing period, the operator had emphasized on the combination research of fine reservoir description and reservoir simulation. So the production performance of the oilfield was improved significantly. The original oil in place (OOIP) has been greatly increased from ODP's 1817×104 m3 to updated 2550×104 m3 by the integrated reservoir characterization. The incremental OOIP is about 733×104 m3. By the end of 2001, the cumulative oil production is up to 824.47×104 m3 of which it is about 32.3% OOIP and water-cut is about 71.1%. According to the results newly forecasted, the ultimate cumulative oil production can be up to 1096×104 m3. The 725×104 m3 of incremental oil recoverable reserves has been enhanced than ODP's 371×104 m3, and its oil recovery factor has been improved from ODP's 20.4% OOIP to more than 42.98% OOIP.

Based on more than eight years producing experience of this oilfield, although it is marginal originally, great development effects and economic benefits have been achieved by using effective stimulation measures, such as drilling multilateral or single horizontal sidetrack wells, drilling additional wells, enlarging draw down pressure, enhancing the liquid production rate especially in the middle water cut period. All these stimulation measures have effectively increased the sweep efficiency, extended the period of production plateau, ensured the average yearly oil production to be more than 4% OOIP lasting out eight years, and also improved the oil recovery. This paper, from the point of view of oil field development and reservoir management, presents the main development strategy and technical experience of this oilfield based on its general situation, geological characteristics and production performance.
Advance on the Tracer Test Technology among Wells
Authors: Ji Bingyu , Sui Xinguang , Wang Qinglin , Li Qun , Anjian Liu , Liu Tongjing
Published: December 2007

The development of the tracer test technology among wells in oil fields has been reviewed in this paper. Both advantages and weakness about the tracer test among wells from the first generation to the fourth generation have been briefly analyzed, meanwhile, a more systematic technology, i.e. comprehensive static and dynamic analyses method has been raised here. The authors proposed that the fourth generation technology with professional interpretation and comprehensive analysis had more advantage. This technology applied in the reservoir development of water drive, steam soak and immiscible displacement has been shown and discussed. Meanwhile, the evaluation on several relevant methods that have been widely used in China has been briefly discussed here. In conclusion, the tracer test technology among wells should be a mature and advanced method during the oil field development at the present age, it should have a widely and excellent prospect of application.
Comparison of Displacement Oil Mechanism of Polymer, ASP and Foam of ASP in Micro Pores and Dead Ends of Pores
Authors: Liu Zhongchun , Yue Xiang'an , Hou Jirui , Zhang Lijuan
Published: December 2007

The polymer flood technology has been applied in large-scale scope in Daqing oil field for about ten years. The area of the pilot projects of ASP flood is enlarging too. The foam of ASP flood, as a new technology based on ASP flood, has been presented. Since the technology centralizes two sides of advantages of ASP flood and general foam flood, its oil recovery is more than the others. Though the area of the pilot project of foam of ASP flood in Daqing oil field isn't very large, the oil recovery of 65% is gotten now. The better perspective of this technology's application has been shown in the pilot project.

Even though these EOR technologies have been successful in pilot tests, the argument about the effect of polymer solution on unit displacement efficiency has existed till now, and the displacement mechanism of ASP flood in heterogeneous formation should be realized again. The foam of ASP flood is a new method to enhance oil recovery. So the results of this paper have an important meaning for their application.

For revealing more clearly the displacement oil mechanism of three technologies, the displacement oil process of polymer, ASP and foam of ASP in micro pores and dead ends of pores have been studied by using microphysical simulation. Moreover, the analysis of dynamic and static forces required to remove a discontinuous oil in micro pores has been implemented by using the points of views of chemistry and Physics of interfaces.
New Development in Water Cut Meter with Salinity Compensation
Authors: Busaidi Khamis , Bhaskaran Haridas , Chen Jige
Published: December 2007

Salinity variation partly causes the inaccuracy of water cut measurement that leads failure to optimize wells production within the capacity constrains of production facilities. In this paper, salinity compensation method is introduced using Gamma-ray absorption technology, as well as Haimo FM2000SC Water Cut meter, which have the built-in Gamma-Ray salinity compensation capability. Test has been conducted on Haimo FM2000SC to determine salinity contents. The compensation is realized by analysis the received radiation count with the different saline water, and obtaining the coefficient value between these two factors. Testing shows that Haimo water cut meter can achieve accuracy of water cut measurement ± 2.0% absolute with 85% confidence factor.
Advances in Surface Measurements for Optimization of Artificial Lift Operations
Authors: Podio A. L. , McCoy J. N. , Rowlan O. Lynn , Becker Dieter
Published: December 2007

Acoustic liquid level tests are performed successfully in many different applications throughout the world. Advanced techniques for acoustic liquid level analysis are required for wells where unusual conditions exist such as very shallow liquid levels, annular partial obstructions, flush pipe, short tubing joints, etc. Some wells have liners, upper perforations, paraffin, odd length of tubing joints, poor surface connections and other conditions which result in an acoustic trace that may be very difficult to interpret. Normally, the computer software locates the liquid level and automatically processes collar reflections to accurately count almost all of the collars from the initial blast to the liquid level. This automatic analysis will determine the liquid level depth for 95% of the wells. However, some wells have conditions or anomalies that these procedures will not function as desired. This paper describes special advanced techniques that can be used to determine the liquid level in wells with these unusual conditions.
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

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

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

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

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

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

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

Natural 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

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

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

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

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.

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Use Of Reservoir Simulation Models In The Development Planning Of The Statfjord Field
Authors: McMichael Claude L.
Published: December 2007

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.
The North Sea And The UK Economy - A Financial Analysis
Authors: Johnson Christopher L.M.
Published: December 2007

The paper covers oil and gas in the United Kingdom and Norwegian sectors of the North Sea. It summarizes an economic and financial research study which the author is conducting. Statistics are given up to end-1977, with future projections. The oil and gas extraction industries are subjected to economic and financial analysis. The effects of the income generated for governments and oil companies are examined in terms of flow of funds and national accounts. The main subject headings are: Reserves, Production, Prices and Values, Energy Policy, the State Oil Corporations, Offshore Investment, Finance, Banking and Insurance, Taxation, Company Sector, Public Sector, Balance of Payments, Gross National Product. Policy decisions are assessed, and future policy options set out.

INTRODUCTION

This paper sets out to describe a research study in which the author is engaged. The project is not yet at the stage where firm conclusions can be put forward. The procedure adopted will therefore be to describe the methodology, and to give tentative findings wherever this is possible. Since many of the approaches employed in the study cannot be pursued in detail, further avenues of enquiry may suggest themselves to other researchers.

The general title of the study is "North Sea oil and gas and its economic significance". It is to be published by the Financial Times in late 1978. A number of economists have already published work in this area. References are given at the end of this paper. Three different lines of enquiry have been pursued in other work, which are all to some extent present in the author's study:An economic and financial analysis of the oil and gas industries themselves, taking into account their growing relative importance in the economies of the UK, and even more, of Norway.Taking the oil and gas industry as given, it is possible to follow the progress of the income which they generate into the different sectors of the British and Norwegian economies, and attempt to forecast how it may affect the balance of payments, the Government budget, or the private sector.A possible variant on 2) is to attempt a normative rather than a positive study, discussing various alternative uses of North Sea income as an exercise in political economy.

The author's study attempts to combine aspects of all three approaches. Comparisons are made, where they are appropriate and possible, between the UK and Norway, on both oil and gas development, and on the broader economic issues. Emphasis is also placed on how the oil companies will, or should, dispose of their North Sea income, as well as on the question of the allocation of Government royalty and tax income. Particular attention is paid to the two State oil companies, BNOC and Statoil, where both Government income and oil company income are involved. Gas is covered as well as oil, and the importance is underlined of achieving clarity in both statements and statistics as to whether oil only is being referred to, or also gas, and if so, whether it include Southern as well as Northern gas.