bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Outlook For U.S. LNG Imports
Authors: Hay Nelson E. 
Published: December 2007

Hay, Nelson E., Manager, Policy Analysis American Gas Association

Abstract
In recent months the desirability of providing increased gas supplies from importation of liquefied natural gas (LNG) has become a major focus of legislative and regulatory attention in Washington. As a relatively "new" energy source, at least in terms of public awareness, LNG has become the focal point for many of the larger issues of the energy policy debate.
This paper will, first, address the role and advantages of LNG importation, second, review the existing and proposed LNG import projects and, finally, summarize the proposed LNG import projects and, finally, summarize the current federal LNG legislative and policy situation.

Introduction
Natural gas currently provides a major contribution to U.S. energy supplies, accounting for almost 30% of all energy consumed in the U.S. in 1976. Gas is used in over half of the nation's residences and commercial establishments, serving over 44 million customers. American industry also depends heavily on gas, which accounts for over 40% of all domestic industrial energy consumption. Moreover, the nation has a major financial commitment to natural gas, with a total utility industry and consumer equipment investment estimated to exceed $100 billion. Half of this investment is represented by almost 1 million miles of underground gas pipeline and main throughout the U.S.
While there are at least 35 years of conventional U.S. natural gas supplies remaining at current levels of use, demand for gas is growing at the same time that gas is becoming more difficult to find and produce. More realistic federal regulatory policies allowing new gas price equivalency with alternative fuels would assure that U.S. natural gas production could be sustained at current levels for an additional 15 to 20 years, but it is clear that sometime after the early 1990's domestic production of conventional gas will begin to decline. This decline, coupled with continued growth in total U.S. energy demand in spite of vigorous conservation efforts, means new sources of gas will be needed to meet future U.S. needs.
Invert Gravel Pack Carrier Fluid
Authors: Donaldson A. , Vitthal Sanjay , Welch J. C. , Nguyen P. D. 
Published: December 2007

Abstract
Invert and all oil/synthetic drilling fluids are being used in high-angle wells, which can be excellent candidates for gravel-packing. This practice has led to a need for a complete fluid system to drill and gravel-pack the reservoir. The new system should also be completely compatible with the fluids and provide the highest degree of formation damage protection.
The Invert Gravel Pack Fluid (IGPF) system can provide an option for carrier fluid for gravel-packing payzone intervals drilled with invert (oil- or synthetic-based) drilling fluids. The primary advantage is the compatibility of the drilling fluid and the gravel-pack fluid. This compatibility helps maintain the highest degree of lubricity of the wellbore, which can aid in the operation of the gravel-pack assembly while providing the highest degree of formation inhibition. The fluid is free of any solids for density, yet, based on current design, provides an invert system weighing to at least 12.2 ppg.
To validate the new system, design work was first conducted in Baroid's Houston Research and Development lab. Additional testing and validation was done at Westport Laboratories and Halliburton's laboratory in Duncan, Oklahoma. Testing consisted of regained permeability, filter-cake erodability, and testing on a gravel-pack simulator loop to help determine the effectiveness of the fluid as a gravel carrier.
This paper describes the testing protocol and fluid design. It also describes the fluid properties to help prove the effectiveness of the fluid as a carrier fluid and shows a relationship with the properties of conventional brines used as carrier fluids.
Development and Use of a Through-Tubing Aluminum Cement Basket
Authors: Lam J. S. , Lee J. R. , Hands N. , Nelson R. , Murphy T. 
Published: December 2007

Abstract
An ingenious and inexpensive removable through-tubing cement basket has been constructed for use in open or cased hole and highly corrosive environments. While the basket was designed specifically for use in deep sour gas wells with sulphur deposition problems, it can be used in any zonal isolation application. A conventional inflatable through-tubing bridge plug can be used in sour service, but its elastomeric components make the plug vulnerable in the presence of sulphur solvents and amine based corrosion inhibitors. The cement basket is constructed from 100% aluminum, which eliminates the problems associated with the elastomeric materials and assures complete removal with acid, thus leaving no debris in the well.
In June 2000, the cement basket was successfully deployed in a deep, sour, horizontal gas well. The 54mm OD basket was run through the tapered 89/73mm OD tubing string before being expanded in the 127mm OD production liner and capped with 4 metres of calcium carbonate chips and 10 metres of cement to provide the pressure integrity. Once cemented, the basket became a plug providing well control for workover operations and a barrier preventing fluid and debris loss to the formation. Subsequently, the permanent packer was milled and retrieved, enabling a new packer and larger tubing to be installed. The aluminum basket with the carbonate and cement cap was successfully milled out using coiled tubing in less than three hours. A small quantity of acid was used to remove any debris from the cement basket and cement sheath from the liner wall.
While the cement basket is a new development, it is deployed using conventional, field proven equipment. It is also simpler and offers the potential for cheaper solutions than a conventional expandable bridge plug. With the experience gained, the next challenge is to build a 42 mm O.D. plug to be set inside 178mm OD casing, which will be more universally applicable for wells in Western Canada and around the World.
Precipitation During the Acidizing of a HT/HP Illitic Sandstone Reservoir in Eastern Saudi Arabia: A Laboratory Study
Authors: Thomas R. L. , Nasr-El-Din H. A. , Lynn J. D. , Mehta S. , Zaidi S. R. 
Published: December 2007

Abstract
Field results indicate that the Jauf reservoir, a deep, high temperature illitic sandstone, is sensitive to conventional mud acid treatments. As a result, an extensive study was performed to better understand the problem.
The focus of this paper is on core flow tests using various inorganic and organic preflushes and mud acid (HCl – HF) systems. Interpretations of the core tests results are supported by chemical, XRD, SEM, and Thin Section analyses. A detailed description of the mineralogy of cores prior to and following an acid treatment is presented with emphasis on precipitation of reaction products, fines migration and other potential damage mechanisms.
Chemical analyses indicated that the HCl preflush extracted the majority of the aluminum during a conventional mud acid treatment. As a result, the Si/Al ratio during the subsequent mud acid stage is a false indicator of hydrated silica precipitation. Additionally, precipitation can occur in acid effluent collected during a core test once the fluid cools to ambient temperature. This results in an erroneous Si concentration and impacts numerous calculations and "conclusions" i.e., reaction kinetics, amount of silica precipitation, etc. The same analogy applies to flowback samples that are used to postulate various downhole phenomena. Although potassium hexafluosilicate was present in core effluents, it was not present in the cores based upon XRD, SEM, and Thin Section examination. Potassium hexafluosilicate was identified as two distinct crystal structures i.e., cubic and pyramidal.
SEM examination showed that most cores exhibited severe alteration of illite and chlorite to yield a significant quantify of clay residue including fines. The residue, severely degraded potassium feldspar (microcline) and quartz fines created formation damage subsequent to treatments with 12 wt% HCl – 3 wt% HF mud acid.
This paper supports the literature in some cases yet spotlights some possible flaws in our understanding of sandstone acidizing.
A New Statistical Method for Interpreting Production Logs
Authors: Li H. , Zhu D. , Lake L. W. , Hill A. D. 
Published: December 2007

Abstract
Production logging suites often consist of some redundant measurements. For example, water holdup in wells producing oil and water is commonly measured by both fluid density and fluid capacitance logs. Each of these logs will contain some error, the level of which is likely different for each log. We present a statistical method for combining multiple log measurements so that the overall error in the interpreted parameter is minimized. The method is applied to multiple holdup logs and to interpreting multiple passes of a spinner flowmeter. The new technique yields the statistically most accurate interpretation and also provides an estimate of the statistical error involved. Synthetic logs are used to prove that the method minimizes the error in the interpreted flow profiles. Field examples of multiphase log suites and multipass spinner flowmeter logs illustrate the applications of the new method.
The Cook Project-Unlocking Potential
Authors: Hill Nigel 
Published: December 2007

Abstract
Enterprise Oil became the Operator of the Cook Field in 1990. A single well had been drilled into the reservoir in 1983, and new 3D seismic data had been shot in 1991. Since becoming Operator, Enterprise Oil reviewed the development options for the Field, until it identified an opportunity in 1998 to unlock the reserves using available ullage in the Shell Expro Anasuria FPSO.
This presentation describes the Field, the potential development options, and the rationalisation in facilities architecture necessary to offer a viable project to its co-venturers for sanction and subsequent development. It then describes the construction work and successful delivery of the project and illustrates how the field has been produced since coming on stream in early 2000. It also discusses the reservoir modelling carried out since coming on stream to assist the decision whether to drill further wells for production or water injection purposes.
System-Modular Management of "Smart Assets" for Recovering the Remaining Potential
Authors: Appleford David E. , Lane Brian W. , Andrews Nicholas J. A. , Smith Ronald G. , Beer Brian W. 
Published: December 2007

Abstract/Introduction
This paper on System-Modular Management presents an efficient, cost-effective method for the development, operation and control of "smart asset" hydrocarbon reservoirs. This method may be successfully utilised for new, mature, marginal or deepwater fields. The paper describes the method and identifies its operational and cost advantages over other development methods.
Fibre Optic Sensing - Case of "Solutions Looking for Problems"
Authors: Eriksson Klas 
Published: December 2007

Abstract
The unique physical attributes and performance characteristics of optical fibers has been well-known for many years, and indeed the transmission properties for data communications was well-known long before full commercialisation was possible for the telecommunication industry. In today’s perspective, it is difficult to believe that fiber optic data transmission systems were indeed "solutions looking for problems", from the early 1970’s. Today we think of high bandwidths, data communications on fibers as extremely routine for the telecom industry.
Similarly for oilfield sensing solutions in the subsea and downhole oil and gas industry, a large number of developers have been supplying potential solutions to sensing problems, but the problems of integrating these technologies with existing subsea and downhole facilities are not insignificant.
The paper will describe some potential solutions to the subject of integrating downhole and subsea fiber optic-based sensors with other subsea and downhole facilities, and identify the necessary interfaces, both physical, electrical and optical.
Some illustrative examples will be presented, and also an appreciation of the present state-of-the-art in fiber sensing for such applications.
WAG Pilot at VLE Field and IOR Opportunities for Mature Fields at Maracaibo Lake
Authors: Alvarez Carlos , Manrique Eduardo , Alvarado Vladimir , Samán Adnan , Surguchev Leonid , Eilertsen Terje 
Published: December 2007

Abstract
Light oil fields in Lake Maracaibo have been produced for several decades under depletion and waterflooding. Due to reservoir heterogeneity and complexity the traditional waterflooding oil recovery is not expected to exceed 30% of initial oil in place. Potential Improved Oil Recovery (IOR) methods capable to boost production from the mature fields are now under investigation and testing by the State Venezuelan Oil Company PDVSA. PDVSA's main IOR technology strategy is based on Integrated Field Laboratory (IFL) philosophy. IFL allows concentrating resources on modern technology evaluation, design IOR processes to solve regional problems, reduce the gap between laboratory screening and the field application phase for most promising recovery methods. The Water Alternating Gas (WAG) pilot at VLE-305 area of Lagocinco field is one of such IOR laboratory fields with the first immiscible gas injection pilot in Lake Maracaibo started in May 2000. The WAG pilot encompasses five production wells, one dual completion injection well and one observation well. The producing reservoir C-23 is a stratified sandstone with areal and lateral heterogeneities. Separator hydrocarbon gas is injected in the dual completion injection well in the WAG mode. Different sensitivity simulations were performed to design and optimize WAG injection strategy. The WAG pilot is now in its second stage of implementation and evaluation. Simulations are focused on tracer modeling and interpretation of production wells response.
Since available injection volumes of hydrocarbon gas for large scale WAG injection projects are not available in the area, other IOR alternatives are being considered. The VLE pilot is again used as a laboratory for screening other potential IOR technologies. Nitrogen injection in WAG and continuum mode, and cyclic water injection are strategies under consideration.
Nitrogen injection facilities will not be operational in the near future, therefore cyclic water injection is considered as an alternative for short-term production improvement under waterflooding. Cyclic injection can accelerate oil production and reduce water cut making production more economic and not requiring significant additional investments in the field. The preliminary evaluation of cyclic injection in the pilot area gives oil production improvement by 2-3%, and expansion of the process over a larger field area could give additional sweep improvement. WAG injection is estimated to improve oil recovery by 10-12% of STOOIP. WAG with nitrogen as injection gas may give 4-6% of STOOIP in increased oil recovery in comparison with waterflooding.
Unconventional Miscible EOR Experience at Prudhoe Bay: A Project Summary
Authors: McGuire P. L. , Holt B. M. 
Published: December 2007

Abstract
This paper summarizes the conceptual development, reservoir simulation, and field testing of a new miscible EOR recovery technique at Prudhoe Bay. Two distinct variations of this technique have been evaluated.
The vertical Miscible Injectant Stimulation Treatment (MIST) process involves completing a production well at the bottom of a thick, continuous, watered-out interval. A large slug of miscible injectant (MI) is injected, followed by a small slug of chase water. The MI sweeps rock not contacted by previous MI injection and drives EOR oil to offset producers. It also creates a mobilized oil bank in the vicinity of the production well. The well can then be recompleted at the top of the reservoir and returned to production service, or used for some other purpose.
It is particularly advantageous to utilize this vertical drive process in conjunction with horizontal wellbores. In the lateral MIST process, a horizontal lateral is drilled along the base of the reservoir from either a production or injection well. MI is injected sequentially into several intervals along the lateral to mobilize EOR oil from previously unswept areas. The lateral well is then returned to normal production or injection service.
Simulation data indicate that the vertical MIST process could recover over 200 Mstb of incremental oil per well at initial rates of up to 1000 stb/D. Calculations for the lateral MIST process indicate potential recovery of more than a million barrels of incremental EOR per lateral.
Field results of the MIST process have been mixed, but overall are encouraging. Incremental EOR response from the first MIST lateral well is currently about 1400 Mstb, resulting in a technical and economic success. Response from three subsequent MIST lateral injectors varied widely. The first vertical well MIST showed little response, but it did provide valuable insight into the performance of the process at Prudhoe Bay. The subsequent vertical well MIST, which had a much larger volume of injected MI, was very successful and has currently recovered over 600 Mstb. Cumulative incremental EOR from the MIST wells through July, 2000, is over 5000 Mstb, with average incremental oil production rates over the past four years of about 4000 stb/D.
Experience of a Reservoir Waterflood Failure and Remediation Treatment in the Stag Reservoir, Australia
Authors: McDiarmid Allan , Ivor Alexander , Ion Andy , Thompson Jeffrey 
Published: December 2007

AbstractThe Stag field operated by Apache Energy Limited is located on the North-West Shelf Australia. Waterflooding is used to maximise production rates and reserves recovery. An unusual failure of the reservoir occurred in late October 2000, between a subsea horizontal injector and a platform based horizontal producer, 2130 ft apart. In effect, a reservoir short-circuit was created between the wells. This reservoir failure circumvented the waterflood and had the potential to isolate reserves between the two wells. Analysis of the failure data indicates the short-circuit was caused by high stresses in the weak reservoir formation. The failure appears to be a wormhole like failure.A tracer study was implemented to provide information on the short circuit dimensions and to design a remedial treatment. The tracer took 2 hours 50 minutes to travel between wells indicating direct communication and a volume of the short circuit flow path in the order of 150-190 bbls.Lack of isolation options through the uncemented pre-perforated liners would make any re-mediation difficult and expensive. This provided motivation to first attempt remediation by a comparatively inexpensive polymer treatment injected through the subsea injector and into the short-circuit. Following the polymer treatment, a cement squeeze through the producer was performed to block the short circuit.This paper reviews the unusual reservoir failure, the tracer study, polymer treatment and subsequent cement shut-off. Included is detail on treatment designs, implementation utilising existing platform equipment and interpretations of the results.This paper is a helpful case study to those designing and implementing water shut offs, identifying waterflood problems and testing low cost re-mediation alternatives. The paper raises an alternative failure mode that could be experienced in waterflood operations in weakly consolidated reservoir rock.
Horizontal Openhole Gravel Packs Boost Oil Production in Brunei
Authors: van Vliet J. P. M. , Lau H. C. , Skilbrei O. B. , Rahman Sakamrin H.A. , Bernardi L. A. , Shumilak E. E. , Halal A. S. 
Published: December 2007

Abstract
In the last three years, openhole horizontal gravel packs have been used extensively in Brunei Shell Petroleum as a sand control method in horizontal wells. Several reasons contributed to the wide application of this completion method. First, production data indicated that horizontal openhole reservoir sections completed with stand-alone screens showed productivity decline possibly caused by screen plugging. Second, gravel packing increases the inflow area and moves damage away from the screen, thus delaying or minimising screen plugging. Third, being an openhole completion a horizontal openhole gravel pack gives a lower skin than a cased-hole completion.
To date, Brunei Shell Petroleum has successfully installed twenty-one horizontal openhole gravel packs with lengths ranging from 100 m to over 1000 m. The unique challenges for horizontal gravel packing in Brunei reservoirs include shallow true vertical depth, long horizontal lengths up to over 1000 m, hole sizes ranging from 6" to 9-7/8", and well paths that crossed faults and long shale sections. Current production from the wells completed with openhole gravel packs accounts for some 18% of Brunei Shell's total oil production.
Assessment of Dulang Field Immiscible Water-Alternating-Gas (WAG) Injection Through Composite Core Displacement Studies
Authors: Nadeson Ganesan , Md. Zain Zahidah , Sayegh Selim G. , Girard Marcel 
Published: December 2007

Abstract
Composite core laboratory displacement studies were undertaken jointly with the Petroleum Recovery Institute, Alberta, Canada to obtain key laboratory data needed to evaluate the applicability of this WAG mode oil recovery scheme in Dulang field. Composite core technology was chosen over conventional single coreflood test as the former provides larger pore volume for fluid contact and movement, reduces saturation end effects and allows assembly of cores from different sands.
Waterflooding was very successful in recovering 56.8% of the original oil in place. Oil water relative permeabilities were derived from the waterflood data and showed the core to be water-wet. Two cycles of gas and water flooding were carried out in rapid succession. In total, about 6.2% of the original oil in place were recovered additionally as a result of these floods. There is also an indication that some more oil may have been recovered from the core by vaporization into the gas stream. The composite core showed evidence of permeability loss and the pressure traces during the floods were quite noisy. This is probably due to the movement of fines and blockage/clearing of pore throats. Geological examination of the core material supports this observation since they were found to contain kaolinite and illite. These possibilities of altering the reservoir rock's flow properties need to be taken into account when designing field applications.
Evaluations of Sub Horizontal Well Performance with Optical and Electrical Probes
Authors: Mas C. , Walterhouse B. , Van Vliet J. P. M. , Rahman S. H. A. 
Published: December 2007

Abstract
Innovative sensing technologies allow direct detection and quantification of oil and gas in multiphase flows. Similar to its sibling electrical probes, the new optical sensor has four probes. The probes are evenly spaced in the pipe cross section on the arms of a centralizer-like tool. The probes orientation in space is monitored through the use of an integrated relative bearing sensor. Image of the gas flow in the well bore is then generated from the measurements of the individual sensor.
Although electrical probes have been available in the industry for several years, its collocation with the full-bore spinner's cage is relatively new to the industry. In the threephase flow environment, the electrical probe gives water and hydrocarbon holdups.
The case examples presented in this paper illustrate the first application of tandem optical and electrical probes in Asia. Operational and interpretation aspects of the surveys in 2 subhorizontal oil wells are discussed in the paper.