bluuebunny/crossref_metadata_2025_split huggingface dataset:
Representation of Steam Distillation and In-Situ Upgrading Processes in a Heavy Oil Simulation
Authors: Sharpe H. N. , Richardson W. C. , Lolley C. S. 
Published: December 2007

Abstract
This paper investigates the role of compositional processes during the steamflooding of a typical California heavy oil. In the past, compositional effects have usually been ignored in heavy oil steamflood thermal simulation studies. Results indicate that the coupled, nonlinear steam distillation/in-situ solvent generation process is capable of significantly reducing oil saturations upstream of the advancing condensation zone, under conditions representative of typical steamfloods. Very fine grid 1 -D and 2-D mechanistic simulation models are required to accurately resolve the relevant physics. An appropriate pseudo-component equation of state, tuned to laboratory data is also essential. A procedure for optimizing the steam distillation mechanism in mature steamfloods using a horizontal well is presented.
Extraction Enabling Technologies: Past Successes and Future Challenges
Authors: McDonell B. , Holmes G. , Mushey N. , Maciejewski W. , Oxenford J. 
Published: December 2007

Abstract
The process for extracting bitumen from oilsand has long been a major area for research and development work at Syncrude. Through this work, many new enabling technologies have been developed - the Tailings Oil Recovery (TOR) vessels, the Inclined Plate Settler (IPS), the Naphtha Recovery Unit (NRU), and the Clark Warm Water Extraction (CWWE) process are a few. These developments have resulted in improved naphtha and bitumen recovery, reduced energy costs and improved environmental performance.
This paper focuses on another enabling technology in the Extraction area - oilsand hydrotransport. This paper discusses the research and development activities since 1989 that have culminated in the construction and startup of the Extraction Auxiliary Production System (EAPS) in 1993.
Learnings from the operation and testing of EAPS have provided important data for the design of hydrotransport - based, bitumen - production systems. These learnings will also serve as a base for development of technology for application on remote lease(s). However, this is not the only new technology required for remote application. This paper will also focus on other new enabling technologies required for off-lease development.
Exploitation of Satellite Oil Pools-Examples from the Ivanhoe/Rob Roy and Fife Field Areas
Authors: Mackertich D. , Boldy S. A. R. , Norbury I. 
Published: December 2007

Extended abstract for SPE 30353 Offshore Europe conference
In recent years in the U.K.C.S, small fields have been successfully exploited both as satellites to existing infrastructure and as standalone projects using floating production techniques. Amerada Hess Limited has pioneered this approach, particularly in two areas in the Central North Sea: Quadrant 15 around the Ivanhoe/Rob Roy and Scott fields and the Fife area in Quadrants 31/39. The former area is close to existing infrastructure and pipelines whilst the latter is over 30 Kms from the nearest facility.
The search for these small fields in the North Sea has been heralded by the widespread use of 3D seismic which has allowed the identification of much smaller prospective structures and more efficient targeting of exploration wells which may be suspended for use as development wells or later sidetracked for optimum reservoir development. The use of 3D seismic for exploration drilling became more common through the late 1980’s and early 1990’s. Such data-sets have helped to more accurately image small, often low relief structures and to optimise the location of exploration and appraisal wells which are often few in number in order to sustain viable economic margins.
In parallel with geophysical developments, advances in offshore engineering technology have helped to achieve lower capital expenditure so necessitating much smaller reserve sizes to make tie-backs economic.
Development Planning for the HPHT Erskine Field
Authors: Shivers R. M. , Brubaker J. P. 
Published: December 2007

Abstract
The Erskine Field will be the first High Pressure / High Temperature (HPHT)* field developed in the North Sea with first gas scheduled in October 19971. The field development concept is to drill six wells and install a Not Normally Manned Installation ( NNMI ) with multiphase export of produced fluids to the Lomond platform 30 km away.
Appraisal drilling demonstrated that Erskine was a marginal field. A multi - discipline, integrated project team was organized to identify the best option for field development. Joint development with a host platform was adopted to improve development economics through reduced capital expenditure resulting from use of existing infrastructure. Several potential host platforms were considered. A fundamental technical objective, driven by commercial considerations, was to design a low cost development option which would allow export of produced fluids over a long distance. The increased "capture radius" opened up several competitive commercial opportunities for joint development by increasing the number of potential host platforms and export systems that could be accessed. The technical design and commercial negotiation process resulted in the Amoco operated Lomond platform being selected as the preferred host.
The cost of the NNMI was reduced by adopting cantilever jackup drilling and multiphase export. The cost of the multiphase pipeline was significantly reduced by qualifying carbon steel instead of corrosion resistant alloy (CRA) pipe. A high temperature insulation system was required for the multiphase pipeline to minimize problems with wax deposition and hydrate formation. Pipeline insulation costs were optimized with respect to operating costs for hydrate inhibition on a full field life basis.
Reservoir Engineering Aspects of the Captain Extended Well Test Appraisal Program
Authors: Pallant M. , Cohen D. J. , Lach J. R. 
Published: December 2007

Abstract
Texaco UK North Sea is operator and 100% license holder of the Captain Field which contains a greater than 1.5 billion barrel, viscous oil accumulation. Oil production from the Captain reservoir will be dominated by the water / oil mobility ratio of 30, resulting in severe water coning from an aquifer underlying a large section of the field. For this reason the field will be developed with pumped horizontal wells with completion intervals of up to 6000 ft. Key elements which will affect reservoir and well performance are horizontal to vertical permeability ratio, critical water saturation, mobile transition zone height, and horizontal well inflow profile. To evaluate these parameters a 30 day vertical water coning test and a separate 90 day extended production test in a prototype horizontal development well, were performed and the measured water cut performance and bottom hole pressures matched with simulation models. Additionally inflow performance in the horizontal well was assessed by production logs which demonstrated that inflow occurred along the majority of the well length. These two tests were conducted in close proximity to each other in a reasonably homogeneous sand, providing the opportunity for simultaneous and consistent interpretation of the observed data. This integration of the results from two tests of different types has resulted in interpretations which have greater levels of confidence attached to them than would have been possible if the two tests had been performed in isolation.
Reservoir Management in the Ninian Field - A Case History
Authors: Omoregie Z. S. , King G. R. , Strang C. , Hodgson P. , Pressney R. A. 
Published: December 2007

Abstract
The Ninian field is a giant oilfield located in the UK Sector of the North Sea. The field, which had an initial oil in place (STOOIP) of some 2,588 MMSTB, has been on production since 1978. Waterflooding commenced early in the life of the field because, like other Brent Formation fields in the North Sea, Ninian has a highly undersaturated oil and limited aquifer support. In October 1994, the field's cumulative oil production reached the one billion barrel milestone. The projected ultimate oil recovery ranges from 1,120–1,255 MMSTB.
This paper presents the reservoir management philosophy and operating practices at Ninian. It discusses the geology and production history of Ninian. The performance of the waterflood is reviewed. The field development strategy, the effect of reservoir heterogeneity and the steps that are and have been taken to improve areal and vertical sweep efficiency are discussed. The paper then discusses the current and future reservoir management challenges facing a mature oilfield like Ninian and how they will be met A recent re-processing and re-interpretation of the 3D seismic has resulted in new maps for the field and improved definition of the severely eroded and highly faulted East Flank of the field. The paper describes the steps being taken to further develop the East Flank based on the new data.
Effect of Pressure Depletion on Fracture Geometry Evolution and Production Performance
Authors: Mukherjee Hemanta , Poe Bobby , Heidt Harmon , Watson Ty , Barree R. D. 
Published: December 2007

Abstract
A fractured well performance evaluation study, in the Frontier formation of the Moxa Arch area (Southwestern Wyoming), revealed pressure depletion due to older 640 and 320 acre-spaced producers along the NE-S W diagonal in 640 acre sections. This was confirmed by six buildup tests across these sections. Reservoir simulation also showed that the production history of some of these old, 320-acre-spaced wells causes enough pore pressure depletion to affect the fracture geometry in the new 160 acre infill offsets on the other diagonal in the same section. This paper presents the simulated pore pressure distribution in the drainage area of these older wells validated by buildup tests and their effects on the principal effective stress field and consequent fracture geometry evolution around the newer wells.
The present paper also shows that depending on the location of the new well in the depleted zone and the original azimuth of the induced fractures, the newly-created fracture may be asymmetric with only one wing of the fracture extending into the depleted area developing significant length and conductivity. This happens at the cost of development of the other fracture wing. Such asymmetric development of fracture wings can negatively impact production, in addition to the production loss due to actual reservoir pressure depletion.
Formate Brines for Drilling and Completion: State of the Art
Authors: Howard Siv K. 
Published: December 2007

Abstract
Low solids drilling fluids based on formate brines (sodium, potassium and caesium salts of formic acid) were originally designed to minimise frictional pressure losses in slim hole drilling applications. In addition, their unique capability of stabilising polymers to high temperatures made them more temperature resistant than any other polymer based drilling fluids. Subsequent work has shown that these brines, because of their high densities and low corrosivity, are also ideal completion and packer fluids. Formate brines have excellent HSE profiles and they are compatible with reservoir fluids, good shale stabilisers, gas hydrate inhibitors, and scale dissolves. Also, a technique has been found for cost effective clean-up and recycling of formate based drilling fluids.
The commercialisation and introduction of these fluids into the field (especially caesium formate) has taken a long time, due to high prices and few manufacturers. This situation is now changing, as the number of manufacturers is increasing, and buy-back arrangements have been made available. Also, a number of successful drilling and completion trials have been carried out.
Use of Hollow Glass Spheres for Underbalanced Drilling Fluids
Authors: Medley George H. , Maurer William C. , Garkasi Ali Y. 
Published: December 2007

Abstract
Interest in underbalanced drilling is growing worldwide at a rate not seen for a new drilling technology since the introduction of horizontal drilling. Compressible, multi-phase fluids, often present in well bores, make underbalanced drilling difficult. This is a result of the intentional introduction of gas into the fluid either at the surface or through parasite or concentric strings or because of fluid influxes into the wellbore from the formation. Many underbalanced drilling problems would be eliminated by the successful implementation of the incompressible, lightweight drilling fluid described in this paper.
Microseismic Mapping of Hydraulic Fractures Using Multi-Level Wireline Receivers
Authors: Warpinski N. R. , Engler B. P. , Young C. J. , Peterson R. , Branagan P. T. , Fix J. E. 
Published: December 2007

Abstract
Hydraulic fracture diagnostic experiments are being conducted at the GRI/DOE Multi-Site (M-Site) located in the Piceance basin of Colorado. Tests described in this paper use s multi-level advanced-receiver system to bu¡!d on previous work that showed the advantages of using a single advanced receiver to monitor microseisms. The current test has a four-level receiver system monitoring four separate fracture experiments conducted over a one week period, and includes a velocity tomographic survey and detailed orientation survey. Hydraulic fractures were monitored from an offset well 210 ft away from the treatment well The results of these monitoring tests show a fracture developing asymmetrically with time, yielding a fracture-wing asymmetry of 2:1. The fracture initially grows within the pay zone to essentially its total length, and then begins to grow upward, and later in time grow downward. Comparison with fracture models gives only a partial agreement in the final size.
First High-Temperature Applications of Anti-Gas Migration Slag Cement and Settable Oil-Mud Removal Spacers in Deep South Texas Gas Wells
Authors: Sweatman Ronald E. , Nahm James J. , Loeb David A. , Porter Dean S. 
Published: December 2007

Abstract
Applications of a new slag cement and spacer system have reduced the chance of gas channels forming in the cement column during cement hydration in deep, hot south Texas gas wells. These slag cements were formulated with water and conventional cement additives to prevent gas migration and to improve interfacial bonding to oil-wet surfaces. Oil-mud removal spacer fluids (OMRS) were also specially formulated to remove oily residues and improve water-wetting of the oil-wet surfaces. These OMRS can also be designed to develop compressive strength when cementing operations have been completed.
Set slag cement provides a tight gas seal with shear-bond healing capacity, as demonstrated by recently developed HTHP shear-bond strength tests. The previously reported phenomenon of healing or regeneration of slag-mix bonds has been reproduced with slag cement. The rapid development of strength at the top of the long cement column and the improved bonding to oil-wet surfaces were the two major improvements provided by the slag cement. OMRS can clean oil-wet surfaces, and then set once the job has been completed.
Laboratory tests and field evaluations based on cement bond logs and pressure tests indicated improved bonding and isolation of the gas zones. Field applications of slag cements and OMRS fluids have led to greater primary and plug cementing successes in south Texas gas wells, and well production economics have improved accordingly.
An Integrated Sandstone Acidizing Fluid Selection and Simulation to Optimize Treatment Design
Authors: Sumotarto U. , Hill A. D. , Sepehrnoori K. 
Published: December 2007

Abstract
An optimized design of a matrix treatment involves fluid selection and acidizing simulations to predict the outcome of the treatment; Many matrix acidizing treatment designs and fluid selections have been successfully accomplished by utilizing expert system technology. However, none of these present a complete and optimized result (i.e., by utilizing the output of the expert system to predict the acidizing outcome using an acidizing numerical simulator). In the meantime, several acidizing computer simulation studies have been conducted separately. This paper presents a study which integrates the treatment design, particularly the fluid selection process, and acidizing simulation for sandstone formations. Required parameters for sandstone acidizing such as acid type, concentration, volume, and injection rate/pressure are first selected using an expert system. The output from the expert system is further used for the input to an acidizing numerical simulator (UTACID). A new sandstone acidizing reaction model, appropriate for a high-temperature environment, and anisotropic medium have been implemented into UTACID to enhance the performance of the simulator. The expert system and the simulator have been integrated to provide an optimization tool for sandstone acidizing treatment design and simulation.
Approach to Casing Design for Service in Compacting Reservoirs
Authors: Cernocky E. P. , Scholibo F. C. 
Published: December 2007

Abstract
Depletion of unconsolidated sand reservoirs can cause compaction of the reservoir sand. This strain transfers load to the casing, and this can kink and crush the casing, preventing workovers and requiring redrilling wells (Figure 1). Early redrilling can have significant negative impact on project earning power, so it is necessary to design casing to withstand compaction loading. This paper explains Shell Oil's new compaction design philosophy for casing to be run in some highly compactive Gulf of Mexico reservoirs. The paper explains the technical tools used to quantify compaction loading; the relative importance of different casing damage mechanisms; and Shell's approach to designing casing to mitigate the influence Of compaction.
Shell's approach to compaction emphasizes minimizing column buckling under axial compaction loads and collapse under transverse compaction loads. The approach to buckling is based on a model that quantifies the ability to work through buckled casing, The approach to collapse is based on a model linking depletion to the load transferred between the sand, cement, and casing. The compaction solution is specialized to Gulf of Mexico sand and reservoir characteristics.
Casing design is only one aspect of the multidisciplinary solution to the compaction problem. Compaction-tolerant sand control must be included in the completion design, and advanced core testing must be used to link the casing design to the stress-strain behavior of unconsolidated sands. Where historical damage exists, downhole casing logging has been used to guide and validate the solution. These other facets of compaction technology go beyond the scope of this paper but have been addressed by Shell Oil's integrated approach to the compaction problem.
Mud Clean-Up in Horizontal Wells: A Major Joint Industry Study
Authors: Ryan D. F. , Browne S. V. , Burnham M. P. 
Published: December 2007

Abstract
This paper describes a major joint industry study into the effectiveness of mud clean-up techniques for horizontal wells involving eight oil and service companies. Experimental work was carried out on a small scale laboratory clean-up rig to quantify mud damage and test breaker effectiveness. Large scale flow loop testing was used to evaluate overall ciean-up techniques including displacement efficiency and damage to pre-packed screen completions.
Tests on a wide variety of mud systems showed surprisingly little difference in the performance, from a formation damage perspective, on clean sandstone cores. Oil based muds were, however, found to produce less damage than water based muds. A range of breakers were tested with each mud system. There was a large variation in the results of breaker testing, with breakers, unexpectedly, sometimes causing an increase in the pressure required to break through mud filter cake and/or formation damage. Whole mud was found to cause significant damage to pre-packed screens; this damage was sometimes, though not always, removed during clean-up. Poorly centralised screens were found to result in large amounts of mud and debris on the low side of the hole.
General Heterogeneous Radial and Linear Models for Well Test Analysis
Authors: Levitan M. M. , Crawford G. E. 
Published: December 2007

Abstract
This paper presents a new analytical method for an exact solu-tion of the presure transient problems for general radial and linear models with heterogeneities. In these models, the stora-tivity and the transmissivity coefficients are considered functions of the distance from the well.
The solution method is based on special transformation of variables which reduces the problem to a diffusivity equation with constant coefficients. This equation is then solved in the Laplace transform domain and the solution is inverted into the real time domain by the Stehfest algorithm. The solution method allows both continuous variation as well as discontinuities of the rock and fluid properties.
The new solution algorithm reproduces exactly all known exact solutions for specific variation of properties including the multicomposite radial and linear model solutions.
Processing of Data From an NMR Logging Tool
Authors: Freedman R. , Morriss C. E. 
Published: December 2007

Abstract
A new pulsed nuclear magnetic resonance (NMR) logging tool, known as the CMR* Combinable Magnetic Resonance tool, is being used worldwide. During the CMR tool development phase, one challenge was to design a robust and economical data acquisition and signal processing scheme for the hundreds or thousands of spin-echo amplitudes that can be acquired during the Carr-Purcell-Meiboom-Gill (CPMG) pulse sequence. This challenge was met by developing a new signal processing and associated downhole data compression algorithm. Data compression is essential to reducing the processing times so that formation T2-distributions can be estimated in real time. Compression of the digital data is possible, without loss of information, because the linear dependency of the NMR measurement kernels results in gross redundancy of the measured spin-echo amplitudes.
An attractive feature of the algorithm described in this paper is that the compression can be performed in the downhole tool, thus substantially reducing the telemetry requirements. The raw spin echoes can also be sent uphole and made available for additional processing.
Logs of CMR porosity, free-fluid porosity, mean relaxation time and rock permeability are computed from the estimated T2-distributions. The accuracy and precision of the CMR log outputs are demonstrated by repetitive Monte Carlo computer simulations in which noisy, synthetic spin-echo amplitudes are generated from known T2-distributions and then processed to obtain log outputs. Monte Carlo simulations are used to elucidate CMR log responses in typical clean sand, shaly sand, and carbonate rocks. The relative insensitivity of the measurements to short relaxation times (e.g., those less than a few milliseconds) is discussed and used to explain the differences between CMR log porosity and "total" formation porosity in shaly formations. We show that CMR porosity is an "effective porosity" that does not include clay bound water and microporosity having relaxation times less than a few milliseconds.
We give examples of statistical fluctuations that can occur on estimated T2-distributions to assist log analysts in recognizing artifacts that are not indicative of actual reservoir rock properties. Field logs that display many of the features of CMR log responses revealed by the simulations are also presented.