bluuebunny/crossref_metadata_2025 huggingface dataset:
Multiscale Reservoir Description Models for Performance Prediction in the Kuparuk River Field, North Slope of Alaska
Authors: Scheihing Mark H. , Thompson Ron D. , Seifert Dirk
Published: December 2007

Reservoir engineering studies of the Kuparuk River Field require reservoir description models at multiple scales. Kuparuk reservoir types range from relatively low permeability, vertically stratified and imbricated lower shoreface sandstones (A Sands) to "thiefy", glauconitic and sideritic shallow marine sandstones with complex permeability structure (C Sands). The field is also heavily faulted, having over 5200 mapped faults with throws typically between ten and several hundred feet.

Geocellular models built for type curve modeling of waterflood and enhanced oil recovery (EOR) processes capture a range of A and C Sand reservoir types. These models are 2600x2600 feet with cell dimensions of 50x50x0.5 feet. Cored wells provide a robust facies and petrophysical model. Both object- and pixel-based techniques are used together with a flow unit-scale zonation to capture key heterogeneities. In the A Sands, this requires capturing the interstratification of sandy and shaly facies using object-based methods. In the C Sands, this requires capturing permeability heterogeneities caused by facies changes and siderite diagenesis using pixel-based methods.

A geocellular model was built to evaluate options to improve throughput rate in the A Sands. This model is 24,000×20,000 feet with cell dimensions of 150x150x0.5 ft. It incorporates 237 faults and 11 flow units. Both object- and pixel-based techniques were used to distribute facies and petrophysical properties. A challenge in this model was in representing reservoir compartmentalization due to faulting of thinly bedded sandstones.

These examples demonstrate the need for "fit-for-purpose" models that best represent key heterogeneities for a given reservoir-modeling/reservoir engineering objective.
Thread Sealant Selection for the Alpine Miscible Injection Project
Authors: Erwin Michael , Ruschau Greg
Published: December 2007

Thread sealants in oil field service are routinely selected based on a variety of requirements including cost, lubricity, and tenacity. Early in the design stage of the Alpine Miscible Injection program concern was raised about thread sealant longevity when exposed to miscible injectant (MI). Previous experience in offsetting North Slope fields has proved that miscible injectant is an aggressive and pernicious leak finder which removes hydrocarbon based lubricants, dopes, greases and sealants from any and all exposed surfaces in wellheads, flowline valves, fittings, lubricators and threaded connections. This paper will describe the laboratory testing and selection process leading to identification of a suitable thread lubricant.
Application of Innovative Strategies and PDC Bit Technology in the Cook Inlet Basin
Authors: Smith Bobby , Langeler Mike , Penrose Bill , Perry Carey , Smith Lee
Published: December 2007

The paper describes recent advances in techniques for rotary drilling interbedded formations of Alaska's Cook Inlet using PDC drill bits. Until recently, use of PDC drill bits in the Hemlock formations in Cook Inlet was inconsistently successful at best. The advent of new drill bit technology that incorporates natural diamond impregnated cylinders to back up the conventional PDC cutting structure has resulted in consistent, best-in-class performance in these punishing drilling environments, as documented by case histories.

In addition, this new PDC bit technology was combined with an innovative dual penetration directional strategy which allowed the operator to maximize exposure to the target Hemlock formations. Developed by the operator in combination with the drilling crew and contractors, the U-shaped dual penetration trajectory has allowed economic commercial development of applications previously not considered PDC-drillable.
Implementation of Intelligent Well Completions Within a Sand Control Environment
Authors: Moore W. R. , Konopczynski M. R. , Nielsen V. Jackson
Published: December 2007

Intelligent well completions have introduced a step-change technology that improves project economics by permitting the operator to actively manage the reservoir. This aspect of asset management is especially important in those wells requiring sand control, often located in remote geographic locations or extreme operating environments, such as deepwater and ultra-deepwater, where the reserves base is high and the subsurface complex. Combining sand control technology with intelligent well technology can be a significant challenge, particularly when producing fluids from multiple, unconsolidated, high productivity zones.

To-date, the successful intelligent well completions that have been completed with sand control have been limited to a maximum of two productive intervals with full time monitoring and control. The limitation has been a result of the architecture of a gravel packed completion, requiring that the interval control valves (ICVs) and pressure and temperature gauges be placed above the zones of interest. While valuable to the asset where employed, some operators have expressed a need to have the control and monitoring equipment placed at or in the completion itself, or to have the capability of adding additional sand control completions to the wellbore.

Design solutions exist that may permit the operator to stack three or more gravel packs in a single wellbore and achieve full intelligent completion functionality. This paper will discuss those solutions and present several examples and case histories.
Revised BOP and Well Control Policies in the Kingdom of Saudi Arabia
Authors: Al-Shammari Hamoud A. , Nordquist Darrell G.
Published: December 2007

Effective blowout preventer (BOP) requirements and well control policies are crucial in maintaining safe drilling and workover operations. These requirements/policies generally are tailored to the individual oil and gas operator’s specific drilling environment. Changes in well profile, depth, temperature, pressure, hydrogen sulfide concentration, and safety margin may require changes in BOP equipment and well control. Saudi Aramco has recently revised their equipment requirements and well control policies in an effort to further optimize drilling safety and efficiency in the Kingdom of Saudi Arabia.

This paper discusses changes in BOP stack arrangements, kill/ choke line requirements, replacement part criteria, elastomer application limits, and use of variable bore rams and shear blind rams. Also included are requirements for number of isolation barriers, pressure testing/maintenance, and minimum overbalance. A new tripping policy and shut-in procedure are also discussed, with the introduction of a new trip sheet and kill sheets. Specific well control policies are provided.
The Use of Self Erecting Tender Rigs for Improving the Economics of Marginal Fields
Authors: Leland Anders
Published: December 2007

Self-Erecting Tender Rigs (SETR’s) have been used in South East Asia, West Africa and the Middle East for 30 years for drilling development wells from fixed platforms.

Inherent in the SETR concept is that equipment required to support the drilling operation such as power, living quarters, etc, is located on the tender, while only equipment actually needed for drilling such as the derrick, topdrive, BOP, etc are installed on the platform. Compared to the use of a platform rig the design load and required deck area of using an SETR is thus only about 1/4 of that needed for a platform rig of comparable capacity.

So far tender rigs have mainly been used for development drilling in water depths down to 800 ft. And this will most likely remain their main application also in the near term.

However, with increased focus on use of dry completions in deep water with the Xmas trees installed on a floating platform like a TLP or SPAR - the self-erecting tender rig concept will present many benefits for field development also in deep water, particularly for marginal field development, where the field economics may depend on solutions using small, remote controlled wellhead TLP’s.
The Legendre Field Development and Geomechanical Program: From Exploration to Drilling to Production
Authors: David Castillo , Ryles Phil , Kirsty John
Published: December 2007

Designing a development drilling program for the Legendre Field required a systematic approach that incorporated the lessons learned during the exploration and appraisal drilling phase. A significant part of the planning endeavor focused on arriving at a geomechanical solution that would prevent many of the instabilities and lost circulation events from being repeated. Detailed image analysis for wellbore failure, and a systematic stress and rock strength analysis was performed to identify the optimal well trajectories and mud weights to successfully drill and complete the production wells. The results of this geomechanical analysis indicated that the stress state in the Legendre Field area is associated with a strike-slip stress regime. Horizontal wells drilled sub-parallel to the maximum principal stress are optimally oriented to ensure wellbore stability in the overburden, while using a lower mud weight within the reservoir reduces the risk of massive lost circulation.
Gas Hydrates as a Resource and a Mechanism for Transmission
Authors: Makogon Yuri F. , Holditch Stephen A.
Published: December 2007

Gas Hydrates as a Resource

During the past century both the world population and energy consumption have increased substantially. The population has grown four-fold in one hundred years, and now exceeds 6 billion. The energy consumption has grown 9.5 times, from 0.9*109 T.O.E. (tons of oil equivalent) to 8.55*109 T.O.E. The information in Fig. 1 reflects the dynamics of consumption of different energy sources in the world. From 1850 to 1950, the main source of energy has been coal. In 1920, the percentage of coal in the world energy balance reached 74 %. In spite of rapid development of the petroleum industry, the percentage of oil has never exceeded 47 % (1972). The proven reserves of oil of 142.1*109 tons [1] is sufficient to last 40 years. At present,, the percentage of oil and gas in the world energy balance is approximately 65 %. The percentage of natural gas in the energy mix is approximately 25%, about the same as coal.

Fig. 2 illustrates the producible quantities of coal, oil, natural gas and gas from hydrate deposits, as presented earlier by Makogon.1 The data in Fig. 2 are based upon proven reserves of hydrocarbons.2 Excluding the possible discoveries of new energy sources, natural gas will be the primary fuel for the coming century for two reasons. First, natural gas is abundant in nature. We know where much of it is located. Second, burning natural gas is much cleaner than burning coal or oil. The world's proven reserves of natural gas at 1/1/2001 were 150.2*1012 m3 (135* 109 T.O.E.). Proven reserves of coal were 498*109 T.O.E.2 At the current level of consumption, the world has enough oil to last for at least 40 years. Known natural gas resources should be sufficient for 60 years or more. However, there could be much more natural gas that is trapped in the deep waters of our oceans and in the arctic in the form of gas hydrates. There are possibly enormous reserves of natural gas in the solid, hydrated state, with an estimated volume of gas-inplace of 14* 1012 T.O.E. If only 10% of that gas could be recovered, it would provide the world with gas for 180 years at the current level of energy consumption.
Rapid Assessment of 3D Seismic and Its Economic Impact
Authors: Roopa Gir , Chi Dah-Ruey David , Tushingham Keith , Xue Jack
Published: December 2007

New innovative approaches are now available that enable three dimensional (3D) seismic data to be rapidly screened, evaluated, and interpreted in a period of weeks, rather than months. This provides a quick and effective way to identify and define prospective targets to help optimize exploration and production (E&P) activities leading to a major impact on the net present value (NPV) of the field.

The rapid seismic screening process identifies major structural and stratigraphic features, blends the major stratigraphic features with 3D attributes, and locates amplitude anomalies via 3D Voxel screening. This process applied to 3D data from the Gulf of Mexico has revealed numerous large undrilled structures in the deeper section below and adjacent to existing fields associated with sand-prone low-stand facies. This approach for screening 3D seismic data sets reduces the risks normally associated with conventional evaluation methods. Its use significantly reduces 3D seismic evaluation time and increases information quality, helping asset managers find and evaluate drilling opportunities quickly and accurately.

Improvements on project economics through the use of this process are demonstrated in a number of economic impact analyses. Typical values of production, commodity prices, and costs from a Gulf of Mexico region are used in various cases to quantify the economic benefits of the rapid seismic screening process. The economic impact of this rapid seismic screening and interpretation approach can be clearly shown.
Identification of Successful Practices in Hydraulic Fracturing Using Intelligent Data Mining Tools; Application to the Codell Formation in the DJ-Basin
Authors: Mohaghegh S. D. , Popa A. , Gaskari R. , Ameri S. , Wolhart S. L.
Published: December 2007

In a detail data mining study about 150 wells that have been completed in the Codell formation, DJ Basin, have been analyzed to identify successful practices in hydraulic fracturing. The Codell formation is a low permeability sandstone within the Wattenburg field in the DJ Basin of Colorado. Since 1997 over 1500 Codell wells have been restimulated. As part of a Gas Research Institute restimulation project 150 wells were studied to optimize candidate selection and identify successful practices.

Hydraulic fracturing is an economic way of increasing gas well productivity. Hydraulic fracturing is routinely performed on many gas wells in fields that contain hundreds of wells. During the process of hydraulically fracturing gas wells over many years, companies usually record the relevant data on methods and materials in a database. These databases usually include general information such as date of the job, Service Company performing the job, fluid type and amount, proppant type and amount, and pump rate. Sometimes more detail information may be available such as breakers, additives, amount of nitrogen, and ISIP to name a few.

These data are usually of little use in complex 3-D hydraulic fracture simulators. These models require additional and more detailed information. On the other hand, the collected data contain valuable information that can be processed using virtual intelligence tools. The process covered in this paper takes the above-mentioned data and couples it with general information from each well (things like latitude, longitude and elevation), any information available from log analysis and production data. The conclusion of the analysis is a set of successful practices that has been implemented in a particular field and recommendations on how to precede with further hydraulic fracture jobs.

In this paper the results of applying this process to about 150 Codell wells during the GRI sponsored project is presented. This process provides an important step toward constructing a comprehensive set of methods and processes for data mining, knowledge discovery, and data-knowledge fusion from data sets in oil and gas industry.
Development of an Intelligent Distributed Management System for Automated Wells (SGPA)
Authors: Cerqueira Jes F. , Corrêa Jose F. , Lepkison Herman , Bittencourt A. C. , Schnitman L. , Jesus A. B.
Published: December 2007

The differences between foreseen results in lift well project related to the obtained in production phase increases preventing and correcting actions necessary to optimize well production. The larger number of wells and its analysis complexity don't allow to conduct the cluster of actions entirely.

To help in this task, the automation of petroleum wells has grown expressively. Over 700 wells in Brazil, at Bahia State, are provided with PLCs using A.I. techniques for their control. This sort of automation generates an expressive amount of data that can be used to optimize the lift systems production. Besides this, it also allows local control and remote observation of many wells in real time basis.

This paper presents an approach for an automated lift well management system, called SGPA. SGPA supports diagnosing and proposes solutions to optimize automated wells production. SGPA focus mainly on Rod-Pump wells management. However, other lift systems can be included as well.

SGPA operates under three main subsystems: (1) Data consistency module, makes the acquisition and consistency of information from different sources. This information is treated and shown in a friendly interface, and it is used in other subsystems. (2) Dynamometric Cards apprenticeships module, allows the user to generate and train the system understanding of the dynamometric cards pattern behavior. These patterns can be used by the PLC's which control the well, and by the SGPA pattern recognition module to support the well diagnose and improve the well lift. (3) Knowledge module that makes well analysis. The knowledge subsystem determine symptoms, makes diagnostics and adds intelligence for the well optimizing and correcting actions. The knowledge representation uses Symbolic Neural Networks (SNN) and Fuzzy Logic (FL) for its constructions and apprenticeship and evolution.

It is understood that lift systems automation comes to be a complex system that distinguishes from other traditional approaches by successfully dealing with huge amount of information to cope its mission, despite the high level of empiricism and apparently erratic behavior due to well peculiarities, demanding rigorous status observation. Such reality and the present technology state-of-art justify SGPA development.
Proper Core-Based Petrophysical Analysis Doubles Size of Ha'py Field
Authors: Bryant William T. , Truman Robert B.
Published: December 2007

The Ha'py Field is located offshore Egypt and is part of the Pliocene producing trend north of the Nile Delta. The original interpretation for the gas in place for the Ha'py Field by Amoco and others was 989 Bcf. Re-evaluation of the field increased the gas in place to 2045 Bcf proven. Subsequent production in the field has substantiated the large increase of the gas in place as a result of the re-evaluation. The initial underestimation of the gas in place was a result of the use of an incorrect log-derived porosity model. This porosity model is not compatible with the petrophysical water saturation relationship used. The incompatibility stems from the fact that petroleum engineers and petrophysicists have different definitions for the terms effective porosity and total porosity. The difference in definitions may lead a petrophysicist to improperly model the well logs to the available core analysis. In addition, the engineer may mis-apply the petrophysicist's results to the reservoir characterization. This improper application leads to a substantial underestimation of hydrocarbon pore volume. The higher the clay and shale content in the reservoir, the greater the error. Definitions will be clarified and explained as they apply to core analysis, reservoir engineering and petrophysics, along with examples using core analysis. Correct modeling of porosity data in these shaly reservoirs lead to the increased estimation of the gas in place.
Maximizing Yibal's Remaining Value
Authors: Team Yibal V2V
Published: December 2007

The Yibal field is one of the cornerstones of Oman's oil production, currently supplying ca. 12 % of the country's daily production. The Yibal field has been on production since 1969 and reached peak production in 1997. Since then the field has been experiencing a rapid decline. This paper discusses the currently ongoing activities to arrest this decline and to ensure that the value of the remaining producible volumes in the Yibal field is maximized using Shell's ‘Volume-to Value’ process.
Prudhoe Bay E-Field Production Optimization System Based on Integrated Reservoir and Facility Simulation
Authors: Litvak Michael L. , Hutchins Lynda A. , Skinner Roger C. , Darlow Bruce L. , Wood Robert C. , Kuest L. John
Published: December 2007

This paper describes the E-field production optimization system (EFOS), recently developed for the Prudhoe Bay oil field in Alaska. EFOS is based on an integrated compositional model of the reservoir and surface facilities. A commercial reservoir and surface facility simulator is used for integrated fluid flow modeling in the reservoir, well tubing strings, surface pipeline network system and surface separation facilities.

EFOS is designed as an operational tool for short-term field production optimization and debottlenecking studies as opposed to a tool for long-term reservoir modeling studies. While full reservoir modeling capability is an option, and is a valid approach to daily optimization for small fields, it is not a practical approach at Prudhoe Bay where there are over 800 producing wells. To facilitate a practical alternative, an option was developed to use well inflow performance curves to predict well performance as opposed to running the full reservoir model.

EFOS consists of the following major components: automatic data preparation, automatic model tuning to match available field production data, production optimization, and a user-friendly interface. Procedures were developed for automatic data collection and creation of simulator input data sets from data gathered by existing process control systems.

In the tuning phase, simulation parameters are automatically adjusted within physically justifiable ranges to match field measurements of well production rates, well tubinghead pressures, and flowline pressures at the specified simulation time.

To optimize production, robust mixed integer optimization algorithms are applied. Well production rates, well allocations to separator trains and, optionally, gas lift rates are selected that maximize field oil production subject to reservoir and facility constraints. The selected objective function is maximized in each simulation time step.

The foreground user-friendly interface is an integral part of one of the Prudhoe Bay process control system databases, with the reservoir simulator running in the background. The interface between the two systems is enabled through a new interactive mode of reservoir simulator operation.

Some examples of the EFOS application are described which also outline the system efficiency. EFOS is based on commercial software permitting its application in a large variety of oil and gas fields.
Coiled-Tubing Fracturing Increases Deliverability, Recoverable Reserves, and NPV of Infill Development Wells in a Mature Shallow Gas Field
Authors: Wolny Stanley F. , Schiffner Glen , Schmelzl Eric G. , Jamieson Merrill , Stromquist Marty
Published: December 2007

A comparative study was undertaken to review the production results, reserve recovery, and economics between conventional hydraulic stage fracturing and coiled-tubing (CT) fracturing on infill development wells in a mature shallow gas field near Medicine Hat in southeastern Alberta, Canada. Selective stimulation through coiled tubing was developed for this area as a response to demands operators placed on service companies to improve the completion efficiency of a shallow gas well with multizone potential. The main benefit of CT fracturing is that each prospective productive interval is selectively stimulated. This translates to improved deliverability, reserve recovery, and project economics. The process also improves logistics, decreases workforce requirements, and minimizes environmental impact. This paper provides in detail how these benefits can be accomplished with coiled-tubing fracturing.
Toto, We're Not in West Texas Anymore; A Challenging Examination of the Historical Global Crude Oil Production Capacity, Demand, Price and the Changing Elasticies
Authors: Jentsch W. A. , Merryman A. A. , Littell G. S. , Groppe H.
Published: December 2007

The basic fundamentals and drivers of changing supply and demand and their affect upon price have changed dramatically through time. Do you recall in the early 80's when the popular belief was that crude would go to $100/bbl or in 1998 when many believed that crude would return to below $10/bbl for the foreseeable future.

The results of this paper will better equip the reader to understand why neither of these beliefs were correct and never will be. This paper will also provide a clearer understanding of the macro supply, demand and pricing environment to assist both the engineers and managers with their critical long-term decision-making.

The drivers in both the short-term and the long-term perspectives of the global crude oil production capacity, demand and price differ. The short-term perspective, which tends to have a greater influence on our strategies and decisions, is typically driven by inventories and influenced by politics, perceptions, seasonal factors and supply disruptions, among others.

The main focus of this paper is on the longer-term perspective or the macro level of global crude oil production capacity, demand and pricing from 1945 to present. In particular, the changes in the elasticity of global demand, supply and price are analyzed and highlighted. Briefly, the regional supply and demand will also be examined.

Trend analysis will include both artificial as well as natural effects such as maturing fields, regulatory effects, and the changing differential (excess capacity) between demand and supply. We will discuss the potential supply and price trends assuming demand continues to increase at the current rate.
An Effective Technique of Estimating Drainage Shape, Magnitude and Orientation in a Low-Permeability Gas Sand
Authors: Robinson Ryan L. , Engler Thomas W.
Published: December 2007

This study presents a methodology to determine the optimal infill location for the Mesaverde Field in the San Juan Basin, New Mexico. Evaluation techniques include: (1) Log-derived cumulative distributions to develop producing interval limits, (2) Seismic analysis to identify fractures, (3) Type-curve analysis to generate reservoir properties, (4) Production decline analysis for establishing inter-well relationships, (5) Geostatistical modeling to distribute reservoir characteristics, and (6) Flow simulation for verification and formation contribution. The result of incorporating these evaluation methods is a map that provides limits to the drainage area.

Specific information obtained is degree of anisotropy, aspect ratio, and the magnitude and orientation of the permeability. In the study area, the dominant fracture orientation was N30°E as indicated by seismic curvature analysis and confirmed with production decline analysis. Type-curve analysis resulted in an average well permeability from 0.10 md to 7.75 md. It was demonstrated that a minimum permeability ratio (kmax/kmm) 13.7:1 was sufficient to match the interfering production response exhibited between wells. Limited infill drilling was identified on the drainage maps, as the existing wells exhibit an average drainage area of approximately 160 acres. Potential recovery was estimated to be 800 MMscf per well for the selected locations with the best chance for success.

A common problem in infill drilling projects is to decide to target prolific areas or low reservoir quality areas in the Mesaverde Group. This study area consists of high equivalent permeability as a function of naturally occurring fracture networks, when compared to the rest of the basin. The likelihood of widespread drainage to occur is high. Therefore, the potential for infill drilling may be limited. This work demonstrated that although limited potential, exists, proper evaluation methods established in this work might be useful to identify the best location.
The Effect of Cement Heat of Hydration on the Maximum Annular Temperature of Oil and Gas Wells
Authors: Dillenbeck R. L. , Heinold T. , Rogers M. J. , Mombourquette I. G.
Published: December 2007

Recent advances in electronics technology have made it possible to monitor and record real-time annular temperatures in operational wells, both during and after primary cementing. The advances have allowed operators to record the entire annular temperature history of their wells, including the critical period when cement hydration occurs. The ability to record these actual temperatures can significantly impact the oilfield cementing industry in several ways. Most significantly, current accepted practice within the industry is to test certain critical aspects of set cement, such as compressive and tensile strength, at bottomhole static temperature (BHST). If the short-term maximum annular temperature is significantly different from the later BHST of the well, then laboratory tests run on cement at a steady BHST may prove to be inaccurate based on the actual temperature encountered by a cement slurry down hole. Also of concern is the fact that since the maximum temperature spike from hydrating cement may not occur until after the cement has achieved an initial set, the magnitude of any subsequent temperature change after the initial set may have profound effects on induced stress in the cement sheath, as well as the casing and formation.

Based on actual field measurements of annular temperatures, the authors will detail how the variable factors of individual heat of hydration, relative annular geometry, and final BHST interact to produce short-term maximum temperatures in the cement sheath. In some instances, these maximum temperatures can vary significantly from the stabilized BHST in a well. The actual annular temperature data was recovered from wells in both North and South America and includes both shallow as well as deep well applications.
The Kitchen Prospects, Cook Inlet Alaska: A Giant Natural Gas Accumulation
Authors: Demarchos A. S. , Warthen R. C. , Davis D. S. , Economides M. J.
Published: December 2007

Natural gas reserves potentially rivaling those of the North Slope have been recently identified in two, never before tested structures, in the Cook Inlet Basin, Alaska. The discovery is a culmination of years of local geological experience, and seismic analysis of existing data using the Energy Absorption Analysis technique (Mitchell, 1997). It is undoubtedly the largest hydrocarbon reservoir discovery in the Cook Inlet, Alaska. They have been named as the Kitchen Prospects. One structure, which has never been tested before, is estimated to hold recoverable reserves of at least 12.7 Trillion cubic feet of gas (Tcf), which is 1 and ½ times the ultimate recovery of the Cook Inlet Basin prior to this discovery (Sherwood, 2001). The total identified recoverable natural gas reserves are estimated to be over 27 Tcf, three times the ultimate gas reserves of the Cook Inlet Basin. Full field development, based on past experiences could exceed 3 billion cubic feet of gas per day (Bcf/d). Current natural gas production in the Cook Inlet is 215 Bcf/year, net (DOE/EIA, 2001).

The limited natural gas market in the Cook Inlet area (local consumption, a fertilizer plant and a small LNG plant) would pose a severe problem in developing new large natural gas reserves. However, the recent national move towards natural gas as the premier fuel of the future the recent energy crisis in California and the West Coast become compelling reasons for the expansion of the existing LNG terminal, or for a new floating LNG, which could supply California with at least 500 MMCF/d. Other options include the substantial expansion of the Ammonia/Urea plant (another 145 MMCF/d) and supplying the city of Anchorage, and Southern Eastern Alaska in general, a political obstacle to the proposed, and more logical, natural gas pipeline from the North Slope under the Beaufort Sea and down the McKenzie Delta to the Canadian pipeline system and into the United States.
Integrating Wellbore Flow Images with a Conventional Production Log Interpretation Method
Authors: Frisch Gary , Perkins Tegwyn , Quirein John
Published: December 2007

Horizontal well production logging (PL) measurements, especially center-sample devices, have been misleading in evaluation of the flowing stream. These inaccuracies are due to the natural segregation of the fluids owing to the difference in the phase densities.

A new multiphase holdup tool and interpretation method has been developed that provides accurate determination of holdups and flowrates in horizontal wells. The multiphase holdup tool uses 12 capacitance-sensing circuits with multiple arm arrangements to provide an excellent image of the holdup pattern. Since these sensors are on the same cross-sectional plane, depth inconsistencies are not a factor in the interpretation. Each sensor responds to the permittivity (dielectric constant) of the surrounding fluids, and the response can be converted to a phase holdup by applying the known sensor calibration. Consideration of each sensor's position relative to the wellbore allows for prediction of the total phase holdup across the entire wellbore cross sectional plane.

Advanced analysis packages allow the user to interact with the computed holdups, providing an easy method of interpretation. Different views of the wellbore, cross-sectional displays, and displays incorporating the wellbore trajectory allow accurate and detailed analysis that is critical for understanding flow in horizontal wells. Once the holdup of each phase (gas, oil, and water) is determined, an additional interpretation package allows a complete production log analysis including flowrates in a very difficult environment. The results of these analysis packages allow an operator to understand, modify, and improve the productivity of a horizontal well.
Application of Shear Anisotropy from a New Generation Crossed Dipole Acoustic Tool
Authors: Fogal Jim , Kessler Calvin , Varsamis Georgios
Published: December 2007

A new generation crossed-dipole acoustic-logging tool acquires data that can be utilized to calculate shear anisotropy. This new tool, the WaveSonic™ tool, was designed using a systems approach so that tool functions such as transmitted pulse shape, center frequency, amplitude and duration are programmable from the surface. Additionally, the tool design is robust enough to allow drillpipe conveyance if well conditions warrant. It can also be combined with other logging tools and is "double-ended", allowing it to be located at any position in the logging tool-string.

Shear data can be collected in orthogonal X-Y directions and oriented by a navigational package using data from a four or six-arm caliper device run with the WaveSonic tool. From these measurements, shear slowness anisotropy can be determined, as well as the direction of the fast shear slowness. These slowness values provide input to a model that calculates maximum and minimum principal stresses and their orientations. Information about principal stresses can be instrumental in optimizing completion and stimulation design. In cases where natural fracture information is desired, crossed dipole data can be used to help detect and orient such fracture systems.
Cable Suspended Submersible Pumps And Their Related Operational And Safety Systems
Authors: Taylor D.F.
Published: December 2007

A unique installation of an electrical submersible pump together with its associated ancillary equipment provides attractive economic logistics when considering crude oil production either for offshore platforms, or in field locations remote from normal sources of supply and service.

The equipment considered here covers the surface and subsurface equipment employed on an offshore, remote platform where an "enhanced" system of recovery of crude may be exploited. The system employed permits greater volumes of production than would be realized if the well's production than would be realized if the well's natural flowing ability were relied upon.

This paper touches upon the problems inherent in such a scheme, some of the solutions encountered in specific installations and improvements incorporated in the subsurface equipment for future installations.

Introduction

The cost of producing oil is a matter of vital importance to those of us who are in the business of producing it. Additionally there are certain factors that affect this cost. The less cost per unit of energy sold, the more profit. This is the reason for this paper.

In certain remote areas, normally requiring large work-over costs, an electric Cable Suspended Pumping System may prove to be a very economical Pumping System may prove to be a very economical method of Production. This may be particularly true for producing satelite fields at considerable distance from other larger producing areas. The most "cost reduction", or "savings" may be ultimately achieved by considering early in the field development dulling phase, the use of the cable suspended pumping system in "enhanced production" mode. By this we mean that the pump and its ancillary equipment is installed during the flowing phase of each well. We will speak only of "enhanced production" systems in this paper.

When contemplating the use of this system on-shore the advantages are:The electrical cable is attached to, and rims, and pulls all of the equipment attached to the pump assembly (Cable Group).A relatively small cable - mast unit is required to service (run and pull) the pump and its associated equipment.Round trip time is held to a minimum.

When contemplating the use of this system offshore, additional advantages are:The surface platform to support the weight of a work-over unit plus pipe pulled from the well is considerably reduced. This means less dollars invested in platform support.Less surface area is required and therefore this also reduces the cost of the platform.Multiple wells may be produced from one platform.The well, or wells, on the platform may be completed in such a way that the well is suspended from the ocean floor, not the platform, this too, results in a reduced strength requirement for the platform.The system is readily adaptable to deviated holes.The cable mast unit may service all the wells on one platform.
Microseismic Response of Well Casing Failures at a Thermal Heavy Oil Operation
Authors: Smith R. J. , Alinsangan N. S. , Talebi S.
Published: December 2007

Imperial Oil's heavy oil operation in northern Alberta utilizes Cyclic Steam Stimulation (CSS) to extract bitumen from the oilsand reservoir (∼400 mKB). The operation currently produces over 120,000 bpd from approximately 3000 deviated wells.

During CSS, the well casings are subjected to thermal stresses due to the cyclic, high-pressure, high-temperature nature of the process. In addition, shear stresses develop in the overburden due to volumetric dilation of the reservoir during steam injection. The combination of thermal fatigue and shear deformations can occasionally result in casing failures at some location along the wellbore, but typically at the top of the oilsand reservoir.

Imperial Oil and CANMET developed the application of passive seismic systems to monitor a volume of the overburden shale for casing failures, as well as for other events. As a result of this monitoring, a model for the seismic signature of well casing failures was developed. The seismic energy and radiation pattern of casing failure events has enabled the passive seismic systems to detect the occurrence of casing failures at the reservoir top, beyond the intended monitoring zone in the overburden shale. Subsequent casing checks have identified that the model detection is correct 88% of the time. In addition, event source location accuracy can be established based on the location of the actual casing failures determined from well workovers. This tool has allowed Imperial Oil to decrease well downtime and develop steaming strategies to reduce the occurrence of casing failures at the top of the reservoir.
Geomechanical Uncertainties and Exploratory Drilling Costs
Authors: Proehl Thomas Strenger
Published: December 2007

This paper presents an investigation of pore pressure interpretation, fracture gradient analysis, and the impact of uncertainties on drilling costs and capital allocation to a well in West Cameron Block 249 in the Gulf of Mexico. Geomechanical uncertainties lead to a range of cost estimates. There is currently no deterministic way of knowing the appropriate empiricism to apply in the analysis of geomechanical conditions that control well designs and cost estimates.
An Oil Selective Inflow Control System
Authors: Freyer Rune , Fejerskov Morten , Huse Arve
Published: December 2007

A system has been developed and tested that reduces the production from zones producing high water cut in open hole screen completions. By use of flotation balls with neutral density in formation water, the system automatically reduces a nozzle area on each joint with increasing water cut. The oil selective inflow control system (OS) is used to reduce flow from zones that significantly contribute to the water cut in a well.

A reservoir simulation tool has been configured to incorporate the OS functionality.
Application of Distributed Electrical Measurements and Inflow Control in Horizontal Wells under Bottom-Water Drive
Authors: Kharghoria A. , Zhang F. , Li R. , Jalali Y.
Published: December 2007

We assess the impact of control enabled by far-field monitoring of bottom-water encroachment on the production performance of horizontal wells. Monitoring can be achieved by electrical measurements distributed along well length against the formation. We assess the depth of investigation resulting from such measurements. Inflow control is achieved by means of downhole valves in a segmented horizontal completion. We examine the impact of valve placement, inflow configuration, and mode of operation on production performance. The combined monitoring and control problem is illustrated by means of synthetic examples.
VES Fluid Allows Minimized Pad Volumes and Viscosity to Optimize Frac-Pack Geometry: Completion Type Evolution in Barbara Field, Central Adriatic Sea
Authors: Mathis S. P. , Pitoni Enzo , Ripa Giuseppe , Ferrara Giovanni , Conte Antonio , Ruzic Mladen
Published: December 2007

When frac-packing near contacts with undesirable fluids, fracture height growth must be minimized. Likewise, when fracturing relatively low-permeability gas sands, the required tip-screenout event may be difficult to obtain due to excessive fluid efficiency leading to excessive fracture growth. One technique to address both of these problems is the use of non-viscosified brine as a fracturing fluid (i.e., water-fracturing).

Water-fracturing limits fracture growth due to its high leakoff, and allows pad volumes to be minimized because proppant concentrations are maintained at low levels throughout the treatment. However, the technique does suffer in that the proppant carrying ability of water does not allow proppant concentration to exceed about 2.5 – 3 PPA. This constraint can lead to reduced near-wellbore fracture conductivity as compared to a properly executed frac-pack using crosslinked fluids. A fluid that has good leakoff and good proppant carrying capacity will provide the opportunity to bridge the gap between water-fracturing and crosslinked gel frac-pack operations. A new generation visco-elastic surfactant (VES) fluid provides this opportunity.

The Barbara field in the Adriatic Sea is a shallow dry gas field and formation sand has to be controlled with gravel pack. It was originally completed with standard gravel packing procedures, which were migrated to water-fracturing techniques during the mid-1990's. While this completion method proved successful, it was desired to increase fracture conductivity while continuing to control fracture geometry. The use of a low-concentration VES fluid allowed such optimization of the frac-pack process, leading to significant productivity improvements. This paper reviews the evolution of completion techniques in the Barbara field that has led to these productivity improvements.
Heather Field: Management of a Mature Offshore Oilfield
Authors: Morel E H
Published: December 2007

Heather field, currently producing about 5,000 bopd, is one of the most mature North Sea oilfields being produced from a large fixed platform. Production from Heather field over much of its life has been marginally economic as revenue and operating costs are finely balanced.

Over the last five years a change of Operator of the field, and simplified ownership, has energised the management of the asset. The new Operator has brought new investment in the field, the platform and exploration of neighbouring satellites. The extra production from infield drilling and well intervention activity has prolonged field life and increased oil reserves. It has also deferred the eventual decommissioning of the Heather facilities.

This paper describes the Operator's approach to managing the asset, and its rationale for the investment in four new platform wells, an active well intervention campaign, and exploration of the greater Heather area. The acquisition of new seismic data has improved the reservoir description of the field and satellites, leading to appraisal drilling of the West Heather area. It reviews the successes and failures of these projects, and describes the main lessons learned, which may be applicable to other fields in a similar economic situation.

The principal factors affecting the company's willingness to invest have been its view of the overall economic outlook, the performance of existing wells and the ability to maximise production from them, the potential of new infield drilling targets to achieve rapid payback, and most importantly, the maintenance of a safe low-cost offshore and onshore operation. Contrary to popular belief the uncertainty in predicting future production from mature fields such as Heather is as great, or greater than predicting future production in younger assets.

The gains to be had from mature assets such as Heather are significant enough to attract the interest of specialist producers. Given favourable tax regimes further investment in other mature fields could yield significant quantities of oil and gas which would otherwise be lost because of premature decommissioning.