bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Kapok Field - A Step Change for Trinidad Gas Developments
Authors: Lumsden P. J. , Balgobin C. J. , Bodnar D. , Brayshaw A. C. , Dyer B. L. , Gainski M. , Hennington E. R. , Burch T. K. , Farmer C. L. , Saldana M. A. 
Published: December 2007

Abstract
The Kapok Field is located some 37 miles southeast of the island of Trinidad, and consists of three separate offshore gas discoveries: namely Sparrow, Renegade and Parang (Fig. 1). Following discovery, four appraisal wells were drilled into the structures in the late 90s to test areas where seismic images were masked by shallow gas. The wells confirmed the presence of gas condensate and minor oil in a total of 18 sands. The development of the Kapok field presents some unique challenges for Trinidad with comparatively shallow multiple stacked pay, aerially extensive reservoirs, relatively thin columns underlain by large aquifers, and poor seismic imaging caused by shallow gas.
To address these challenges a multidisciplinary reservoir description and stochastic modelling study was conducted to improve understanding of water behaviour - the key reservoir risk - and to plan optimum locations for the field development wells. The integrated workflow for the project incorporated seismic mapping, 3D structural modelling, the use of detailed core descriptions and field analogues, as well as both full field and single sand reservoir simulation.
The development of Kapok will be implemented in two phases: Phase I will develop the reserves associated with Sparrow and Renegade, Phase II will target Parang. Phase I calls for 16 high angle/horizontal, openhole gravel packed wells and the installation of a new 20 slot normally unmanned, remotely operated platform. The wells, some capable of delivering 200+ Mmcfd, will initially deliver 1 bcfd for processing on the new Cassia ‘B’ Central Processing Unit (CPU), prior to delivery into the 48in Bombax pipeline and transportation to the Trinidad mainland. The Cassia ‘B’ CPU will have the capability of processing 1.6 bcfd of gas, 50 Mstbd of crude/condensate and 25 Mstbd of water from the existing Cassia, Immortelle and Flamboyant fields, as well as from Kapok and any future developments in the area. The CPU will be one of the largest offshore processing units in the world. With the Kapok platform and the Cassia Hub, BP is working to promote overall safety and environmental standards within Trinidad, with re-injection of produced water and drill cuttings disposal forming part of the enhanced environmental measures.
Advanced Large-Scale Coalbed Methane Modelling Using a Conventional Reservoir Simulator
Authors: Tan Thomas 
Published: December 2007

Abstract
A conventional reservoir simulator was modified to model coalbed methane reservoirs using the approach presented by Siedle where an immobile oil phase is used to represent the bulk coal and the gas volume adsorped on the coal's surfaces is computed as solution gas-oil ratio. The simulator was validated against published results from coalbed methane models. The speed of the model was tested for a large problem with 120,000 cells. A dual grid system to model gas desorption, flow through low permeability matrix to high permeability fracture cleats in the coal seam was shown to more accurately reproduce initial delay in gas production while dewatering. Enhanced recovery using N2 and CO2 injection was simulated using single grid and dual grid systems. Expected incremental recovery of methane was obtained using the single grid system. However no additional recovery was obtained using the dual grid system due to extensive bypassing of the injected gas in the fracture grid system. This indicates additional physical mechanisms are at work.
Hydrocarbons Injection to Improve Recovery from Gas Condensate Reservoirs: A Simulation Approach
Authors: Harouaka A. S. , Al-Hashim H. S. 
Published: December 2007

Abstract
Hydrocarbons injection has been reported, in the open literature, to improve both gas and condensate recovery from gas condensate reservoirs. The injection process is considered once a liquid ring builds up around the well bore thereby reducing drastically gas delivery. Actual reservoir and fluids data from a deep gas condensate well, completed in five distinct layers, were used as input to a compositional reservoir simulator to assess the following:
1) Evaluation of various (four) injection fluids; 2) impact of shut in and injection as well as shut in alone; 3) Impact of minimum flowing bottom hole pressure constraints; 4) evaluation of a single layer model equivalent to the original multi layer well; 5) impact of shut in and injection on the equivalent single layer model; 6) impact of shut in alone on the equivalent single layer model and 7) evaluation of a binary system (77% C1 and 23% nC4) at a relatively low pressure and temperature.
From the four tested injection fluids the C4-C5 mixture gave the best results for productivity restoration. The injected C4-C5 mixture, at the high dew point considered in this work, creates, through miscibility, a single liquid phase around the well bore.
At the trailing edge of the liquid-phase around the well bore the capillary number increases sharply indicating a sharp drop in IFT. Hence the gas coming in towards the well bore is just like the liquids fully miscible with the liquid phase around the well bore.
Simulation runs done on a binary system, at a low dew point pressure indicate the miscible process will also work but the single phase around the well bore will be a vapor phase.
Increasing Well Productivity in the Wilcox Lobo Trend
Authors: Schubarth S. K. , Bazan L. W. , Becnel J. L. , Wagner A. L. , Manrique J. E. 
Published: December 2007

Abstract
The Wilcox Lobo Trend of south Texas contains vast quantities of natural gas in low permeability formations. Economic production from low permeability gas sands is possible through the use of hydraulic fracturing. Through the years, varying hydraulic fracturing techniques have been used to recover the gas from this trend. The success of fracturing techniques varies and depends on many factors. Several authors have demonstrated the importance of propped fracture conductivity in the production enhancement process. Without sufficient conductivity in the proppant pack, fracture fluid cleanup and adequate hydrocarbon production are difficult to achieve. The work presented in this paper will show the evaluation of these different completion techniques and products used in the Wilcox Lobo Trend by the authors. The work demonstrates the importance of fracture conductivity, supports previous work in other producing regions and presents some additional methods for achieving increased conductivity. The techniques, products and evaluation methods used in this paper can be used to benefit other operators in the Wilcox Lobo Trend as well as those working in other low permeability gas formations.
Field Study on the Use of Cement Pulsation to Control Gas Migration
Authors: Dusterhoft Dale , Wilson Greg , Newman Ken 
Published: December 2007

Abstract
Gas flow into cement is a serious problem that results in surface vent leaks and poor zonal isolation in many wells throughout Western Canada. This paper discusses the field testing and application of a new technique called cement pulsation to control this problem. Cement pulsation involves applying short, frequent 700 kPa pulses to the annulus following cement placement. These pulses reduce the gel strength of the slurry, which allows full hydrostatic pressure to be transmitted downhole across the gas zone, thus preventing gas from entering the annulus. This paper also discusses background theory, examines research on the depth to which pulses travel in the annulus, and presents a field study in which pulsation was used to control gas migration in Western Canada.
Numerical Studies of Gas Production from Methane Hydrates
Authors: Moridis G. J. 
Published: December 2007

Abstract
EOSHYDR2 is a new module for the TOUGH2 general-purpose simulator for multi-component, multiphase fluid and heat flow in the subsurface. By solving the coupled equations of mass and heat balance, EOSHYDR2 can model the non-isothermal gas release, phase behavior and flow of fluids and heat under conditions typical of common natural hydrate deposits (i.e., in the permafrost and in deep ocean sediments) in complex formations, and can describe binary hydrocarbon systems involving methane.
EOSHYDR2 includes both an equilibrium and a kinetic model of hydrate formation and dissociation. The model accounts for up to four phases (gas phase, liquid phase, ice phase and hydrate phase) and up to nine components (hydrate, water, native and dissociated methane, a second native and dissociated hydrocarbon, salt, water-soluble inhibitors and heat). The mass components are partitioned among the phases, and their thermophysical properties can be described at temperatures as low as -110 °C. Dissociation, phase changes and the corresponding thermal effects are fully described, as are the effects of salt and inhibitors. The model can describe all possible hydrate dissociation mechanisms, i.e., depressurization, thermal stimulation, salting-out effects and inhibitor-induced effects.
Results are presented for four test problems exploring different mechanisms and strategies for production from typical CH4-hydrate accumulations. The results of the tests tend to indicate that CH4 production from CH4-hydrate is technically feasible and has significant potential. Thermal stimulation is capable of producing substantial amounts of hydrocarbons, and its effectiveness can be enhanced when coupled with depressurization and the use of inhibitors.
Wildcat Hills Gas Gathering System Case Studies: An Integrated Approach From Reservoir Development Through to Sales Pipeline Delivery
Authors: Marsh Jack , Kenny Joseph 
Published: December 2007

Abstract
This paper presents a study of the development of the Wildcat Hills Viking gas reservoirs from the drilling of the exploration well to the complete development of the facility infrastructure, using a total systems approach. The Viking gas reservoir was initially identified in 1958 but remained undeveloped while a deeper Mississippian gas reservoir has produced for over 40 years. The shallower Viking reservoir had been by passed due to its low matrix permeability as well as the low initial reservoir pressure. These two observations made development of the Viking gas unfeasible at that time. Following up on data obtained from the deeper Mississippian gas wells, and using modern seismic interpretation and geological concepts, a trend of viable gas wells was discovered in the Viking sand. The challenges of determining the actual reserve potential, developing an efficient gas gathering and processing infrastructure leading to optimum and economical management of the Wildcat Hills project are outlined in this paper.
Roles of the Fracture System and State of Stress for Gas Production from the Basement Reservoir in Hokkaido, Japan
Authors: Kazuhiko Tezuka , Namikawa Takatoshi , Tamagawa Tetsuya , Day-Lewis Amy , Barton Colleen 
Published: December 2007

Abstract
Fractures in the Yufutsu reservoir may be divided into two sets based on apparent aperture measured in electrical image data. Large-scale fractures having centimeter-order apparent apertures (termed "mega"-fractures) are considered to contribute to gas production by acting as conduits, while relatively small-scale fractures contribute to gas storage and migration. The interaction between fractures and the state of stress may also control productivity. Analysis of wellbore failure revealed a NE-SW orientation of the maximum horizontal compressive stress (SHmax), with a small variation from the west (SHmax oriented N30E) to the southeast and north (SHmax oriented N60E). Modeling indicates that the general stress state is strike-slip (Shmin &lt; Sv &lt; SHmax). Coulomb failure analysis of natural fractures in the current strike-slip stress state reveals that steeply dipping fractures striking to the northeast-southwest are critically stressed and therefore most likely to be permeable. Wells in which this is the dominant fracture set are therefore most likely to be productive. The predictions agree closely with observed production in the wells. The results from this study are sufficient to provide guidance for future drilling and completion decisions for the Yufutsu Field.
Applied Reservoir Characterization for Maximizing Reserve Growth and Profitability in Tight Gas Sands: A Paradigm Shift in Development Strategies for Low-Permeability Gas Reservoirs
Authors: McKinney P. D. , Rushing J. A. , Sanders L. A. 
Published: December 2007

Abstract
This paper proposes an alternative tight gas sand reservoir development strategy that allows operators to maximize gas recovery and net present value while minimizing capital expenditures. Our approach employs a "parallel" development technique where many reservoir performance evaluation and field development activities are performed almost concurrently, thus allowing an operator to identify the optimum well spacing early in the field's life. Successful application of this "parallel" development approach requires a coordinated reservoir description and characterization plan, reservoir modeling, and reservoir monitoring and surveillance. We also illustrate the economic advantages of our strategy with examples from a hypothetical tight gas sand reservoir.
Hydraulic Fracturing: The Forgotten Key to Natural Gas Supply
Authors: Duda J. R. , Boyer C. M. , Delozier D. , Merriam G. R. , Frantz J. H. , Zuber M. D. 
Published: December 2007

Abstract
By most accounts, natural gas demand in the United States (U.S.) is expected to significantly increase during the next two decades, from 23 trillion ft3 in 2000 to over 33 Tcf in 2020. The Energy Information Administration projects that 22,000 gas wells will have to be drilled in 2020 to meet this demand - up substantially from the 15,200 wells successfully drilled and completed in 2000. Further, a significant portion of the U.S. future supply of natural gas is expected to be produced from these unconventional sources - formations that typically require hydraulic fracturing to produce at economical rates. Given this forecasted scenario, a critical and comprehensive assessment of the role that hydraulic fracturing plays in supplying natural gas in the U.S. has been initiated.
Permeability, Pore Pressure, and Leakoff-Type Distributions in Rocky Mountain Basins
Authors: Craig David P. , Eberhard Mike J. , Odegard Chad E. , Ramurthy Muthukumarappan , Mullen Rebekah 
Published: December 2007

Abstract
The permeability, pore pressure, and leakoff-type interpreted from more than 1,200 diagnostic fracture-injection/falloff tests were collected in a database and statistically evaluated for four Rocky Mountain basins. The statistical analysis includes the range of observed permeability and pore pressure and the fracture leakoff-type distribution.
Specially designed "mini-frac" or diagnostic fracture-injection/falloff tests were routinely implemented throughout Rocky Mountain basins beginning in late 1998 for the sole purpose of estimating reservoir-engineering parameters. Using three recently developed analysis methodologies, more than 1,200 tests have been analyzed to determine permeability, pore pressure, and leakoff type.
The analysis reveals that pressure-dependent leakoff, fracture-tip extension during shut-in, and fracture height-recession during shut-in are the most common leakoff types. Overall, pressure-dependent leakoff, which can be indicative of highly productive fractured reservoirs, is the most common leakoff type in all Rocky Mountain basins. The analysis also shows order-of-magnitude variation in gas permeability within all basins with observed gas permeability ranging from less than 0.001 md to greater than 0.10 md.
Evaluation of a Statistical Infill Candidate Selection Technique
Authors: Guan L. , McVay D. A. , Jensen J. L. , Voneiff G. W. 
Published: December 2007

Abstract
Quantifying the drilling or recompletion potential in producing gas basins is often a challenging problem, due to large variability in rock quality, well spacing, and well completion practices, and the large number of wells involved. Complete integrated reservoir studies to determine infill potential are often too time-consuming and costly for many producing gas basins. In this work we evaluate the accuracy of a statistical moving window technique that has been used in tight gas formations to assess infill and recompletion potential. The primary advantages of the technique are its speed and its reliance upon well location and production data only.
The statistical method was used to analyze simulated low-permeability production data sets; moving window infill well predictions were then compared to those from reservoir simulation. Results indicate that moving window infill predictions for individual wells can be off by more than 50%; however, the technique accurately predicts the combined infill production estimate from a group of infill candidates, often to within 10%. The accuracy of predicted infill performance decreases as heterogeneity increases and increases with the number of wells in the project. Cases evaluated in this study included realistic well spacings and production rates and a significant amount of depletion at the infill locations. Due to its speed, accuracy and reliance upon readily available data, the moving window technique can be a useful screening tool for large infill development projects.
Case Study: Including the Effects of Stagnant Water in Gas Gathering System Modeling
Authors: Young James , McNeil Ralph , Knibbs Jeffrey 
Published: December 2007

Abstract
This case study outlines and details the steps taken in constructing a gas gathering system model of the Pendor field in south-eastern Alberta.
The challenge was to identify and model the effects of stagnant water in the pipelines and wellbores, and then quantify the deliverability potential resulting from the removal of said liquids.
Also included are the methods used to calibrate the gathering lines, calibrate the well deliverability at sandface and wellhead, history match to verify reserve data, and the importance of first hand verification of pressure anomalies and their causes.
Productivity of Horizontal Wells Completed with Screens
Authors: Yildiz Turhan 
Published: December 2007

Abstract
An integrated flow model is developed to simulate the flow into horizontal wells with screens. The model is composed of a multi-segment horizontal well model and a near-wellbore model. The multi-segment horizontal well model predicts the pressure losses in a bounded reservoir. The near-wellbore model simulates the fluid flow through the damaged/collapsed zone around the wellbore, mud-cake, wellbore/screen interface, gravel-packed annulus and screen itself.
Using the model, we investigated the effects of degree of screen damage, non-uniform damage removal, mud cake properties, and blank pipe insertion on horizontal well productivity. We examined and compared the long-term horizontal well performance in terms of rate decline and cumulative production as a function of time.
New Development Case History: Midnight Sun
Authors: Eck Daniel J. , Reinbold Eric W. , Lundgren Carl E. , Daggett Paul H. , Westergaard Edwin H. , Rollins Francis O. , Young Jim P. , Bakun Frederick E. 
Published: December 2007

Abstract
The Midnight Sun field is located on the North Slope of Alaska near Prudhoe Bay (Figure 1). The field was discovered in 1997 by ARCO Alaska, Inc. and Exxon when drilling the Sambuca #1 exploration well. The discovery well encountered approximately 100’ of high quality Kuparuk sand analogous to the adjacent Pt. McIntyre field. The field was further delineated in 1998 with the Midnight Sun #1 well. Proximity to Prudhoe Bay infrastructure allowed early production from the Midnight Sun reservoir with production commencing in October 1998.
The Midnight Sun accumulation occurs in a low relief graben, containing an estimated 40 to 60 MMSTB of Original Oil In Place (OOIP). A gas oil contact (GOC) extends over a significant portion of the reservoir.
A 3D reservoir simulation model was constructed, calibrated to early field performance and used to study development options. A mid-field waterflood was identified as the best development plan. Simulation runs indicated that the mid-field waterflood would provide good recovery while isolating the upstructure gas cap for future depletion.
Waterflood operations commenced in October of 2000 using produced water from the Prudhoe Bay facility. Waterflood response was observed in the third quarter of 2001, characterized by increased oil production rate and a dramatic GOR collapse. Three additional wells were drilled in the fourth quarter of 2001 to complete the Phase II drilling program. Results from these wells have confirmed the geologic model used for development planning.
Performing a High Resolution surface Gravity Survey to Monitor the Gas Cap Water Injection Project, Prudhoe Bay, Alaska
Authors: Brady Jerry L. , Ferguson John F. , Aiken Carlos V. L. , Seibert John E. , Chen Tianyou , Hare Jennifer L. 
Published: December 2007

AbstractThe world’s first 4-D surface gravity surveillance of a waterflood is being implemented at Prudhoe Bay, Alaska. This monitoring technique is an essential component of the surveillance program for the Gas Cap Waterflood Project. A major factor in the approval process for the waterflood was to show that water movement could be economically monitored, with a very limited number of wells penetrating the waterflood area. Conventional monitoring techniques would have been cost prohibitive since they would have required the drilling of numerous surveillance wells. Modeling studies indicate that density changes associated with water replacing gas can be readily detected using high-resolution surface gravity measurements. Modeling of the gravity data determines the mass distribution, mass balance and flood front location.This paper will focus on how to perform an extremely accurate, high-resolution surface gravity survey in the Arctic. Details on survey methodology, meter testing and calibration will be covered. The use of gravity meters in combination with the NAVSTAR Global Positioning System (GPS) for location and elevation will be described. Field tests at Prudhoe Bay indicate that gravity survey accuracy of 5-10 µGal can be achieved using relative gravity meters in combination with GPS. Model results, using reservoir simulations, have indicated that gravity surveys with this accuracy should be able to account for greater than 95% of the injected water.
Permanent Fiber Optic Monitoring at Northstar: System Installation
Authors: Pruett Eddie , Abshire Phil , Holt Barbara M , Sherritt J. Allen 
Published: December 2007

Abstract
BP's Northstar field, on the North Slope of Alaska, represents the first multi-well, new field development to incorporate downhole fiber optic pressure and temperature monitoring. Between 2001 and 2003, permanent fiber optic pressure and temperature gauges will be installed in 16 wells. This paper discusses the installation of the first 6 fiber optic systems at Northstar in the winter of 2001. All aspects of the installations will be described, including planning, logistics, run-in-hole during completion, and system commissioning. Elements common to and different from conventional gauge installations will be examined. In particular, special requirements for a fiber optic system installation in an arctic environment will be identified.