bluuebunny/crossref_metadata_2025_split huggingface dataset:
High Strength, Ultra-Lightweight Proppant Lends New Dimensions to Hydraulic Fracturing Applications
Authors: Rickards Allan R. , Brannon Harold D. , Wood William D. , Stephenson Christopher J. 
Published: December 2007

Abstract
Since the earliest fracturing treatments over 50 years ago, many different materials have been used including sand, glass beads, walnut hulls, and metal shot. Today's commonly used proppants include various sands, resin-coated sands, intermediate strength ceramics, and sintered bauxite, each employed for their ability to cost effectively withstand the respective reservoir closure stress environment. As the relative strength of the various materials increases, so too have the respective particle densities, ranging from 2.65 g/cc for sands to 3.4 g/cc for the sintered bauxite. Unfortunately, increasing particle density leads directly to increasing degree of difficulty with proppant transport and a reduced propped fracture volume for equal amounts of the respective proppant, reducing fracture conductivity. Intuitively, one expects a lesser density proppant would be easier to transport, allowing for reduced demands on the fracturing fluids, and if it had sufficient strength, would provide increased width, hence, enhanced fracture conductivity.
Previous efforts undertaken to employ lower density materials as proppant have generally resulted in failure due to insufficient strength to maintain fracture conductivity at even the lowest of closure stresses (1,000 psi). Recent research on material properties has at last led to the development of an ultra-lightweight material with particle strength more than sufficient for most hydraulic fracturing applications. The current ultra-lightweight proppants have apparent specific gravity's of 1.25 and 1.75 g/cc. Laboratory tests will demonstrate exceptional fracture conductivity at stresses to 8,000 psi. This paper will present data illustrating the performance of the new ultra-lightweight proppant over a broad range of conditions and a discussion of relative performance in field applications.
An Environmentally Friendly, Highly Effective Hydrogen Sulphide Scavenger for Drilling Fluids
Authors: Davidson Eric , Hall John , Temple Colin 
Published: December 2007

Abstract
Drilling into a hydrogen-sulphide (H2S) rich formation presents risks that the highly toxic gas might be carried to the surface and released, thus creating a serious hazard. To mitigate this risk, it is standard practice to run the drilling mud at high pH and to include a sulphide scavenger. Commonly, such scavengers are based on iron oxide or on zinc compounds. Iron oxide has the advantage of being environmentally friendly but, at high pH, has a slow reaction rate. In contrast, the zinc-based scavengers have a faster action. In particular, chelated zinc, which is water soluble, has a very fast reaction rate. The action of the zinc in any form is to precipitate the sulphide as a zinc salt. Precipitation prevents release of hydrogen sulphide gas, but it contaminates the mud and cuttings with zinc. In many parts of the world, disposal of material containing zinc is a problem because it is regarded as a toxic heavy metal. For example, discharge is forbidden in many international waters and cuttings for disposal on land may have to be treated as special waste.
E&P Forum recommends product substitution as a source reduction method of reducing waste disposal problems and associated costs. Accordingly, a less toxic alternative was pursued.
A new scavenger has been developed that relies on the affinity between iron and sulphide. The active chemical is a form of ferrous iron complexed with a carbohydrate derivative. It is highly soluble in the brine phases of water-based mud and will not precipitate at a pH over 12. Because the iron is in solution, the reaction with sulphide is instantaneous and complete. The paper deals with the environmental implications of zinc vs. iron and the development of the new scavenger. The paper will present details of case histories concerning operations on a reservoir containing 25% H2S. Even in these demanding conditions, no H2S was detected at the surface.
All Lost-Circulation Materials and Systems Are Not Created Equal
Authors: Whitfill Donald L. , Hemphill Terry 
Published: December 2007

Abstract
Controlling circulation loss during well construction is more than just selecting the proper type of lost circulation material (LCM).1 A fully engineered approach is recommended. This approach incorporates a number of planning tools, including: Borehole stability analysisHydraulics modeling to estimate equivalent circulating density (ECD)Drilling fluid and LCM material selection to help minimize effects on ECD.
Planning should include means to provide on-site monitoring using pressure while drilling (PWD), and connection flow monitoring and timely application of LCM and treatments.
The following practices are advocated to provide the best available technology: Base the amount of LCM on volume rather than weight.Pretreat with LCM before drilling high risk lost circulation zones.Add subsequent treatments as sweeps, rather than adding into the bulk drilling fluid system in the suction pit.
Results from a new laboratory study on LCM testing are discussed and compared to more classic large scale laboratory data from Drilling Engineering Association (DEA) joint industry experiments conducted in the 1980s.2 Results are discussed that demonstrate a rationale for pretreating drilling fluids with combinations of resilient graphitic carbon (RGC) and sized calcium carbonate (SCC) where a high probability for loss of circulation exists.
Simplified treatments using engineered combinations of LCM in a single sack may be used for different applications, such as drilling depleted sands, seepage losses, and severe lost circulation. In some cases a more specialized treatment may be required, such as a two component system pumped down the drillpipe and annulus simultaneously, forming a flexible seal in the fracture, and effectively isolating the borehole pressure from the fracture tip.
Requirements of Downhole Flow Control Valves
Authors: Gai H. 
Published: December 2007

Abstract
A brief review of Down Hole Flow Control technology shows that it is still far from mature. Efforts on characterizing DHFC valves highlight some fundamental challenges, and indicate that DHFC valves are flow control devices, not pressure control devices as chokes are. The DHFC valve requirements are then detailed, including the functionality, mechanical, and reliability requirements and other considerations, and an attempt is made to dispel some of the misconceptions. Some simple guidelines for system/valve design and selection are also presented, providing a useful tool for the user. An example is given, demonstrating the complexity of the interactions of multiple well and reservoir parameters and some of the design basics, and the use of a simple spreadsheet simulator.
It is concluded that while the DHFC technology has proved itself as viable and capable of delivering huge value to the industry, there remain some serious technical challenges, which call for continued and concerted efforts. The complex requirements should be managed with a system approach not just focusing on discrete components. Analytical tools are needed for proper system design and validation in the given application environment to achieve success.
MC305 Aconcagua SCSSV Control Hydraulics Problems Uncommanded and SCSSV Closure Problems
Authors: Hare Simon , May Dwayne , McCalvin David , Martyniak Paul 
Published: December 2007

Abstract
The Aconcagua field, operated by TotalFinaElf, is located in 7000’ of water in MC305, and is part of the Canyon Express development. Aconcagua is a dry gas field, comprising four subsea wells. The Canyon Express project involves a commingled tieback of three dry gas fields, owned and operated by different companies, through a jointly owned twin 12" flowline tieback to a third party host platform at 56 miles distance.
Two problems have been experienced in the operation of the SCSSVs, initially during the flow-back testing, and later in the production phase. The first problem was the rapid rise in hydraulic pressure in the control lines during well start-up; this is related to a problem with the design of the pod hydraulics, and is found on all four wells in the Aconcagua field. The second problem is related to uncommanded closures of the SCSSV; this problem has been experienced on three out of the four Aconcagua wells, to varying degrees of severity. Although procedural mitigation methods have enabled the MC305-1 and MC305-2 wells to operate correctly, the uncommanded closures have continued in the MC305-4 well during the first four months of field life.
The MC305-4 well is located in 7,055 feet of water; top of reservoir is located at around 12,500 feet TVD below MSL, and the SCSSV is set at 9,400 feet below MSL. The TR SCSSV is a Schlumberger TRC-DH type; it has dual redundant pistons with a gas spring system to counter balance the hydrostatic pressure of the Transaqua HT control fluid (4,300 psi at the SCSSV depth).
This paper describes the hydraulic design of the control pods, the reasons for the increase in hydraulic supply pressures in the control lines, and the procedural steps taken to mitigate over-pressurisation of the SCSSV hydraulics. Also described are the system modes associated with the uncommanded SCSSV closures, and the diagnostic testing carried out to establish the reasons for the closures. The detail of the steps taken to avoid the closures is offered, both with procedural and hardware modifications noted.
Hydrate Prevention and Methanol Distribution on Canyon Express
Authors: Cooley C. , Wallace B. K. , Gudimetla R. 
Published: December 2007

Abstract
The Canyon Express field in deepwater Gulf of Mexico is a development consisting of multiple subsea gas-condensate wells owned by different companies. Each deepwater well (ranging from 6400 to 7250 foot water depth) flows into one of two 57 mile, 12" flowlines which tie the subsea wells to a shallow water host platform on the Continental Shelf. The production from each well is predominantly methane gas but also consists of produced water and condensate. Due to the nature of the production and the combination of high pressures / low temperatures expected, the potential for hydrate formation is a serious concern to system operability. To adequately protect the system against hydrate formation and deposition, injection of hydrate inhibitor (methanol) at each subsea well from a common umbilical system is being employed. Although wet gas metering is being used at each well to measure gas and liquid rate, water content per well cannot be accurately predicted. Thus, a robust methanol injection strategy was required to effectively inhibit hydrate formation. This paper presents the design of the methanol injection system and development of the overall injection strategy. Examples from the early field life of the Canyon Express development will be presented which demonstrate the application of this injection strategy to the system operation.
Simulations of Compositional Gradients in Hydrocarbon Reservoirs under the Influence of a Temperature Gradient
Authors: Pedersen K. S. , Lindeloff N. 
Published: December 2007

Abstract
A model based on irreversible thermodynamics is presented for simulating the compositional variation with depth in petroleum reservoirs with a vertical temperature gradient. By assuming that the system is at a stationary state, and that no heat flux exists in an isothermal reservoir, the influence of a temperature gradient can be expressed in terms of partial molar enthalpies of the present components. Experimental data are presented for the compositional variation with depth in two high-pressure gas condensate reservoirs with a vertical temperature gradient. The observed compositional variations with depth are higher than in an isothermal reservoir and can be modeled quite closely using the proposed model.
SEC Defined Reserves Booking: What the Petrophysicist Needs to Know
Authors: Truman Robert B. , Davidson James A. 
Published: December 2007

Abstract
This paper addresses the petrophysical analysis issues related to the Securities and Exchange Commission definition of proved, proved developed, and proved undeveloped oil and gas reserves. It informs the practicing petrophysicist of the current SEC views concerning the relative merit of the various engineering and geological data typically utilized in reserve booking efforts so that he can be conversant with the important concepts and make the proper recommendations to ensure the appropriate data have been acquired and the applicable analyses performed. Current state of technology is addressed along with issues as they relate to the application of SEC definitions. There are numerous issues related to these definitions including the criteria for reasonable certainty; the weight given to the analysis of open-hole well log data; considerations for what constitutes representative fluid volumes from wireline and other well tests; and the role of core analysis, pilot studies, analogous reservoirs as well as other data sources such as seismic data to establish reservoir continuity. The strengths, limitations and use of these various data sets to establish proved developed reserves are presented along with areas requiring further industry clarification or development.
For example, according to the SEC, "Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test."1 However, in the Gulf of Mexico, reserves are often classified as proved in the absence of production or flow tests when certain criteria are met. This occurs when the case for reasonable certainty is effectively made. In other cases, proved developed reserves such as thin bedded sections may require a flow test, cores and a more complete set of well logs and high resolution borehole information.
Contractual, economic, and regulatory issues will not be addressed, nor will issues relating to drainage areas, recovery factors, enhanced recovery or other engineering-related issues be discussed.
Introduction to Methods to Fracture More Than 30 Zones in a Well-Per-Day and Used on About 1,000 Wells-Per-Year
Authors: Demin Wang , Shijin Pan , Chaoyang Xie , Gang Wang 
Published: December 2007

Abstract
This paper introduces a method to fracture more than 30 zones in a single well per day and also how to fracture low permeability zones when the impermeable barrier(s) to high permeability and high water cut zones are only about 0.5 m thick and not create channels in the cement sheathe.
The above methods are used in a large scale in Daqing Oil Field (about 1,000 wells per year since 1980). The results are quite good, cumulative incremental oil production by these fracturing methods is about 60 million tons; the fracturing costs per ton of incremental oil is about $6.
An Integrated Selective Testing Service for Horizontal Wells
Authors: Al-Sharji H. , Hook P. 
Published: December 2007

Abstract
Horizontal well operators use the interpreted results of tubing-conveyed production logging as a basis for well treatment decisions. However, the complexity of near-horizontal flow regimes and flow behavior of in-field laterals still provide a challenge to log evaluation in terms of both accuracy and time required for interpretation.
This paper presents a field example demonstrating the success of a service that integrates surface and downhole equipment for a simpler alternative to current horizontal production logging techniques. At the surface, a mobile multiphase flowmeter is connected to the well flowline. Two pieces of equipment are conveyed downhole using coiled tubing: a resettable inflate packer configured to plug flow, and a pulsed neutron logging tool contained inside a housing purpose-built to enable packer operation while acquiring log measurements.
The service involves consecutive packer setting at strategic points along the producing well length. Production from the section isolated by the packer is determined by the change in multiphase flowmeter recordings at the surface before and after packer setting. Downhole logging sensors verify packer element seal, and monitor borehole pressure in real time.
By measuring flow at the surface, the service is completely insensitive to the complexity of near-horizontal multiphase flow regimes downhole. Well production instability is immediately observed and countered by extending the recording time during packer setting. The accuracy of the resultant flow profile is not degraded by downhole gas, not open to interpretation, and more reflective of well remediation results involving zonal shutoff.
Because multiphase production along the length of the lateral is accurately evaluated in real time, the service offers an efficient, cost-effective alternative to horizontal production logging. Following this diagnostic evaluation, well operators are now in a position to treat laterals using the coiled tubing unit already in operation at the wellsite.
A Combined Diagnosis and Treatment Service for Multilateral Injector Wells
Authors: Al Farsi N. , Ojulari B. , Hook P. , Staal T. W. 
Published: December 2007

Abstract
Patterns for multilateral (ML) injector and producer wells are successful in boosting reservoir oil recovery, but waterflood sweep uniformity is critical in this environment. Until recently, complete quantitative evaluation of injection water distribution in ML legs has only been possible by whipstocking workover pipe into each lateral leg, and by subsequent log sensor pumpdown operations. Any well remediation operation was conducted separately from the logging operation. The complexities and costs of evaluating and treating MLs have left well operators with limited practical and economical options for remediation.
The last 10 years have seen successful equipment development for selectively entering level 1 and 2 lateral extensions—classifications of the Technical Advancement of ML wells (TAML) (Fig. 1)—with coiled tubing (CT). This paper describes a new, combined diagnosis and treatment service enabled by conveying logging sensors into any selected leg of a ML well. Initially, the relative injection distribution between legs is measured by pulsed neutron logging the injection-water velocity along the well's natural path. Then a real-time decision is made as to which legs to enter for further evaluating the water-injection profile. Evaluation results are available in real time for planning treatments to improve waterflood sweep efficiency. The CT unit, using the same lateral reentry equipment as for log sensor conveyance, can then do stimulation or water shutoff treatments. If desired, the ML can undergo post-treatment evaluative logging.
ML injector diagnosis and treatment are now possible with a single combined operation at the wellsite, without a workover or drilling rig.
The ability to simultaneously access and log all levels of live ML wells with CT, for real-time decisions and action on optimal treatment, provides a cost-effective option for optimizing recovery.
Perforating System Selection for Optimum Well Inflow Performance, Alba Field, Equatorial Guinea
Authors: Snider Phil , Rindels Chuck , Folse Kent , Hardesty John , Clark Nathan 
Published: December 2007

Abstract
An ever-expanding range of reservoir scenarios continues to challenge oilfield operators and service companies to provide completions that will not only produce at optimum levels but will also accelerate return on investment (ROI). Unfortunately, in attempting to satisfy these needs, developers often overlook a very important component of the completion scenario — the perforation process. This paper will demonstrate that focusing perforator system performance on reservoir productivity rather than on the shaped charge, performance optimized for concrete testing (which is the case with API Section I) can ultimately lead to significant improvement in well inflow performance. The discussion will demonstrate that:
The actual performance of given shaped charges at in-situ conditions for both penetration and effective flow should be evaluated to make perforating decisions for the completion process. Applying the perforating concepts discussed in this paper significantly optimized well productivity for a major West Africa project in which wells with 1000 feet of perforations were to be completed.
Economic penetration studies, perforation performance evaluation, optimization using a Perforation Flow Laboratory, and tests on the Alba-Field core samples were conducted using unique strategies.
An innovative live-well modular gun system was utilized on this project to maximize well inflow performance.
The system will provide significant cost savings to the operator and will generate much improved well productivity over that which had been attained in the exploration well program.
A New Thermal Insulating Fluid and Its Application in Deepwater Riser Insulation in the Gulf of Mexico
Authors: Wang Xiaolan , Javora Paul , Qu Qi , Pearcy Rick , Starliper Art 
Published: December 2007

Abstract
Undesired heat loss from the production tubing, or uncontrolled heat transfer to outer annuli contributes to the formation of gas hydrates and causes the deposition of paraffin and asphaltene materials to reduce the production rate. The successful application of thermal insulating fluids in the last several years has demonstrated that such fluids can effectively control the heat loss. In some cases, heat loss from the produced fluids due to conduction and convection can be reduced by more than 90% when compared to traditional packer fluids.
Recently, a new thermal insulating fluid system with superior thermal properties has been developed. Compared to the current existing insulation fluids, the new insulating fluid system provides high viscosity at low shear rate range to reduce fluid convection rate. And it also provides lower viscosity at high shear rate range to facilitate the fluid placement. The new fluid with improved insulation properties has proven to be an attractive alternative to the current insulation method for deepwater risers. This paper highlights the development of this new thermal insulating fluid and its application in deepwater riser insulation in the Gulf of Mexico. Laboratory data and field cases are also presented to demonstrate the effectiveness of this fluid system.
Learning Along the Way: Mahogany Field in Trinidad After 5 Years, 700 Bscf, 22 MMbo and No Lost Time Incidents
Authors: Mackow H. M. , Bally Y. K. , Perry J. T. , Lachance D. P. 
Published: December 2007

Abstract
On November 07, 2002 the Mahogany Field in Trinidad passed five years since operations started, and the field continues to have a great record in safety, production and drilling. The field has had no DAFWC (Days Away From Work Cases) since operations started in 1997, and that has also included 2 major phases of drilling on both platforms Mahogany A and Mahogany B. Cumulative production to date is 0.7 Tscf of gas and 22 MMbo.
In August 2002, the Mahogany Field produced over 30,000 STBOPD, while in May 2001 (before the current drilling phase started) the production was 12,200 STBOPD. This production story is another remarkable milestone for the field. Apart from being the largest combined gas and oil producing field in bp Trinidad and Tobago LLC (currently 479 mmscfd and 38,000 STBOPD – October 2002) the field now produces more hydrocarbon liquids than any other field in Trinidad and Tobago. This paper reflects on how and why the field was developed, shares some of the technologies employed and highlights the challenges and successes that the teams have faced in developing the field.