bluuebunny/crossref_metadata_2025_split huggingface dataset:
Low-Risk TAML Level-5 Multilaterals in the South China Sea
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 88542, "Development of Low-Risk High-Level TAML Level-5 Multilaterals in the South China Sea," by Jonathan Park, SPE, and Duo Wei Shen, SPE, Baker Oil Tools, and Li Wen Yong and Yuan Fu Cun, ConocoPhillips China Inc., prepared for the 2004 SPE Asia Pacific Oil and Gas Conference and Exhibition, Perth, Australia, 18-20 October.
The ConocoPhillips Xijiang fields in the South China Sea required multilaterals to increase oil production from the limited number of available platform slots. Further development in this area depended on slot recovery to maximize production and minimize hole collisions caused by frequent sidetracking in cluster wells. This paper discusses a method used to install low-risk multilaterals in these wells. This method reduced the risk and time associated with Technology Advancement of Multilaterals (TAML) Level-5 multilateral completions. This method eliminates the need for a high-risk-washover operation.

Introduction
The Xijiang fields, including the Xijiang 24-3 and Xijiang 30-2 fields and the Xijiang 24-1 satellite field, are approximately 130 km from Hong Kong. The fields are developed with two 24-slot platforms: Platform XJ 24-3 for Xijiang 24-3 field and Xijiang 24-1 satellite field, and Platform XJ 30-2 for the Xijiang 30-2 field.
The Xijiang fields include multiple, laminated production sands from 1400 m true vertical depth subsea (TVDSS) to 2850 m TVDSS. The thickness of the production sands ranges from 1.5 to 92 m, with bottomwater or edgewater drive mechanisms. The porosity of the production sands ranges from 8 to 30%, and permeability ranges from 800 to 8000 md. The unconsolidated production sands require sand-control completions.
The 24 drilling slots on Xijiang 30-2 plat-form were used up in March 2002; the 24 drilling slots on Xijiang 24-3 platform were used up in December 2003. The limitation of drilling slots significantly constrained the future development of Xijiang fields.
To further develop the Xijiang fields, infill wells use sidetracking of existing wellbores. The first sidetrack for the Xijiang 30-2 field was initiated in March 1999; the first side-track for the Xijiang 24-3 field was initiated in June 1999; and the first sidetrack for the Xijiang 24-1 satellite field was initiated in July 2003. As of September 2004, a total of 39 sidetrack projects had been completed. Frequent sidetracking makes hole collisions a significant risk in Xijiang fields.
To maintain daily oil production and increase ultimate recovery in the Xijiang fields, multilateral wells were adopted. Multilaterals reduce hole collision risks. When a well’s production decreases to its economic limit, it becomes a multilateral candidate. Because of the unconsolidated formation around the casing exit, hydraulic integrity and sand exclusion around the junction area in multilateral wells is critical. To optimize production, re-entry into the main bore is required for some sidetracks.
Understanding Torque and Drag: Best Practices and Lessons Learned From Captain Field Extended-Reach Wells
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 91854, "Understanding Torque and Drag: Best Practices and Lessons Learned From the Captain Field Extended-Reach Wells," by G. Rae, SPE, Chevron Upstream Europe, and W.G. Lesso Jr., SPE, and M. Sapijanskas, Schlumberger, prepared for the 2005 SPE/IADC Drilling Conference, Amsterdam, 23-25 February.
Torque and drag (T/D) analysis was used for successful extended-reach drilling (ERD) in the Captain field in the North Sea. The tactics used in overcoming issues such as drill length and the associated risk are explained. The applicability of available T/D-reduction technologies and why many of them were eliminated as possible solutions reinforced the criticality of good T/D analysis on this project.

Introduction
The Captain field is in the U.K. sector of the North Sea, approximately 81 miles northeast of Aberdeen, in a water depth of 369 ft. Because of the high viscosity and low temperature of Captain oil, long horizontal wells are required to drain the reservoirs effectively (Fig. 1). Although the field was discovered in 1977, it was not until 1995 that appropriate technology was available and development approval was received. The field was developed as a phased installation with two drilling centers tied back to a central floating production, storage, and offloading vessel.
Before starting the Captain subsea development, 29 directional wells were drilled in the first, or Area A, development of the Captain field. The requirements of the subsea, or Area B, development were demanding. These were factored into the rig selection and subsequent drilling specification. The Captain sands are shallow, at approximately 3,000 ft true vertical depth (TVD), and soft. The reservoir is thin but prolific. Geosteering or precise directional control in horizontal sections was necessary.
The completion design required a 250-ft straight section (dogleg severity less than 1.0°/100 ft) no more than 350 ft TVD above the reservoir. This section is where the submersible pump would be placed. The design also dictated that the directional build rate shallower than this pump tangent be less than 4.5°/100 ft. The wells would be drilled with water-based mud (WBM) for environmental considerations. A WBM system also was necessary in the horizontal sections to achieve inflow-performance requirements.
Overview: Health, Safety and Environment (July 2005)
Authors: Veil John 
Published: February 2015

It is a real challenge to summarize the three disciplines of health, safety, and environment (HSE) in just half a page. All three have important roles in the petroleum world, yet they are vastly different. Specialists in one discipline may know little about the other disciplines. Unlike most other JPT topics, regulatory issues contribute significantly to management of HSE.
In March, professionals from many countries gathered in Galveston, Texas, for the biennial SPE/EPA/DOE Exploration and Production Environmental Conference. Most of the papers featured here, along with numerous other interesting papers, were presented at that meeting. This year, the conference included additional discussion on safety and security.
The process of finding and producing oil and gas and bringing products to market produces many effects on the air, water, and land, as well as on plants, humans, and animals. The industry has made great strides in the past few decades through technology development and pressures from governments. Yet the public does not perceive this industry as being a “clean” industry; we have a long way to go to improve both reality and perception. Regulatory initiatives and public pressure will force new developments in managing drilling wastes, produced water, and air emissions, among other industry byproducts.
The oil and gas industry has opportunities to use its vast skills and impressive technological capabilities to help society meet other health and environmental needs. Two examples that readily come to mind are injection of carbon dioxide for enhanced recovery or for permanent sequestration and treatment of produced water for beneficial reuse in arid areas.
Finally, we must remember that the men and women in this industry frequently work in extreme environments and with complicated and potentially dangerous equipment. Accident rates and fatalities continue to be higher for the E&P sector than for other heavy-industry sectors. It is critical to improve the safety of oil and gas operations to protect our work force. Many challenges remain in HSE.
Available from the SPE eLibrary: www.spe.org
SPE 94476 - “Cost-Effective Treatment of Barium from Coalbed-Natural-Gas Produced Water,” by J.T. Cline, SPE, Anadarko Petroleum Co.
SPE 93796 - “Environmental Regulatory Framework in Europe: An Update,” by E. Garland, SPE, Total
SPE 88673 - “Comprehensive Solutions to Drilling-Waste Management,” by Abdullah Al-Suwaidi, ADCO, et al.
SPE 94371 - “Increased Access to Federal Lands Through Data Sharing,” by S.D. Belieu, SPE, Nebraska Oil and Gas Conservation Commission, et al.
SPE 94177 - “Potential Nontraditional Uses of Byproduct E&P Produced Sulfur in Kazakhstan,” by P.W. Beall, Battelle Memorial Inst., et al.
Seabed Effects of Synthetic-Based-Drilling-Mud Cuttings in the Gulf of Mexico
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 94086, "An Assessment of Seabed Impacts of Synthetic-Based-Drilling-Mud Cuttings in the Gulf of Mexico," by J.M. Neff, SPE, Battelle; A.D. Hart, Continental Shelf Assocs. Inc.; J.P. Ray, SPE, Oceanic Environmental Solutions LLC; J.M. Limia, SPE, Baker Hughes Drilling Fluids; and T.W. Purcell, American Petroleum Inst., prepared for the 2005 SPE/EPA/DOE Exploration and Production Environmental Conference, Galveston, Texas, 7-9 March.
The U.S. Gulf of Mexico (GOM) Comprehensive Synthetic-Based-Muds (SBMs) Monitoring Program used a combination of physical, chemical, and biological measurements to survey 14 drillsites on the continental shelf and continental slope of the GOM where cuttings generated while drilling with SBMs had been discharged. Three continental shelf and three continental slope sites were selected for more intensive investigation. The objective was to document the distribution of cuttings in drillsite sediments and to characterize the areal and temporal extent of chemical and biological changes resulting from cuttings discharges.

Introduction
The largest volume of waste generated during drilling is drilling mud and drill cuttings. There are three basic types of drilling muds: water-based mud (WBM), oil-based mud (OBM), and SBM. Most wells in U.S. waters have been drilled with WBM. WBM and associated cuttings usually are permitted for discharge in federal waters. OBM offers several technical advantages over WBM for difficult drilling operations; however, OBM and OBM cuttings have never been permitted for ocean discharge in U.S. waters.
The need to drill increasingly difficult deepwater and deviated wells, coupled with the economic and safety advantages of ocean discharge of cuttings, has led to development of SBM. SBM is designed to be less toxic and to biodegrade in marine sediments faster than OBM, while providing the technical advantages of OBM when drilling difficult wells. The U.S. Environmental Protection Agency (EPA) defines SBM as drilling mud in which a synthetic-based-fluid (SBF) chemical is the continuous phase with water as the dispersed phase.
Guest Editorial: The Role of a Consultant - What Is It Really?
Authors: Ellul Ivor 
Published: February 2015

The title of the article might cause one to pause momentarily since I am sure that we all know what a consultant is and what his associated role should be. I am equally sure that if one were to ask a group of consultants the same question, the answers would be interestingly varied. As an engineer, consultant, and ultimately, a business owner, I take this opportunity to distill more than 25 years of experience that I have used to build a leading consulting organization, while sharing some of the more controversial issues that arise.
Dictionaries proclaim that a consultant is an expert who gives advice. Additionally, it is believed that the word consultant has been used for some time, since before 1892. So, what is it that has driven the need for this "species" from as far back as the 19th century? The answer is simple and partly has to do with the expertise factor, but, above all, it has to do with the time/money factor. A client employs a consultant to get something done more quickly (and, one hopes, better) than he could have done it himself given his lack of available and qualified resources. As a result, the job should cost less. In addition, the value added must always be significantly greater than the value paid out.
Consultants are prevalent in a number of industries including medical, aerospace, transport, and construction. The energy industry is no different, and one comes across a wide spectrum of, on the one hand, independent consultants and, on the other, larger organizations geared to take on and execute large projects. Wherever you are in the spectrum, there are a number of fundamental prerequisites that define a true consultant. These include the following:
Expertise. This comprises the technical and, possibly, commercial background necessary to address the problems at hand and deliver a successful solution.
Experience. Armed with the technical knowhow, this relates to the fact that the individual or company has successfully executed the type of work currently under consideration.
Deliverability. No matter how smart and how experienced one is, if one cannot deliver on time, on budget, and to the client's satisfaction, then it is all for naught, and the client's time and money have been wasted.
Integrity. This is a key element in today's business environment and hinges on one doing what one says one is going to do while ensuring that there are no conflicts of interest along the way. This is especially important given the fact that a consultant is usually exposed to sensitive client data that must not be seen by any third party. Sanctity of contracts is key, whether constituted on the basis of a handshake or resulting from a 20-page document.
Overview: Well Stimulation (July 2006)
Authors: Dusterhoft Ron 
Published: February 2015

As I write this, my third and final opportunity to select technical papers for this feature, I find myself in Baku, Azerbaijan, the birthplace of our modern-day petroleum industry. This is an amazing place, where the history of our industry collides with the present. It is still possible to see some of the earliest commercial oil wells that were dug by hand and cased with wood; while just offshore, huge new development projects use some of the most modern technology available to the industry.
Even with current prices for oil and gas, our industry struggles to supply the energy to support the dynamic economies of the world today. Achieving the goal of long-term, low-cost sources of hydrocarbons will require significant technology advances in the area of well stimulation. From the papers I have seen this year, it is apparent that these technological advances will affect many different portions of our industry, from old, mature fields, where significant reserves have previously been economically unattractive, to the new, major ultradeepwater projects that are being evaluated today. The challenge will be to increase productivity, and then to maintain that increased productivity throughout the life of the field to provide improved ultimate recovery.
New and innovative stimulation technologies are emerging that will shake the foundations of some of our tried and proven methods. Still, in other cases, we see elegant enhancements to improve the performance of existing technologies. It appears that the future challenge will be for us to find more-cost-effective ways to improve well productivity.
It appears that well stimulation will remain a dynamic part of our industry. I am hopeful that this industry will continue to be attractive to new, innovative, and challenging minds who will continue to shape the future of the petroleum industry.
Well Stimulation additional reading available at the SPE eLibrary: www.spe.org
SPE 98329 "Evaluation of Nonlinear Fracture Relative Permeabilities and Their Impact on Waterfrac Performance in Tight Gas Sands" by R.B. Sullivan, SPE, Anadarko Petroleum Corp., et al.
SPE 98314 "A Breakthrough Fluid Technology in Stimulation of Sandstone Reservoirs" by F.E. Tuedor, SPE, Schlumberger, et al.
SPE 97659 "Controlling Formation Fines at Their Sources To Maintain Well Productivity" by P.D. Nguyen, Halliburton, et al.
SPE 97161 "Proppant Flowback Prevention—A New Technology for Low-BHST Applications" by D.E. Johnson, SPE, Hexion Specialty Chemicals Inc., et al.
Continuous Improvements in Acid Fracturing at Lake Maracaibo
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 96531, "Acid Fracturing in Lake Maracaibo: How Continuous Improvements Kept on Raising the Expectation Bar," by B. Burgos, Shell Venezuela S.A.; M. Buijse, SPE, Shell Intl. E&P; E. Fonseca, Shell Venezuela S.A.; and A. Milne, M. Brady, SPE, and R. Olvera, Schlumberger, prepared for the 2005 SPE Annual Technical Conference and Exhibition, Dallas, 9-12 October.
The Maraca limestone formation is a part of the Cogollo carbonate group below Lake Maracaibo, Venezuela. Acid fracturing with an organic-acid system has proved to be a pivotal completion strategy for achieving higher productivities and increasing reserves. The main challenges are the relatively high hydrogen sulfide (H2S) content, 280°F reservoir temperature, the asphaltenic nature of the crude, and the long completion tubing that limits pump rate.

Introduction
The Maraca limestone formation is a 20- to 30-ft upper member of the Cogollo carbonate group at 15,000 to 16,000 ft in the Urdaneta West field below Lake Maracaibo, Venezuela. Reservoir volumes and productivity are attributed mainly to matrix development, in contrast with the rest of the Cogollo, where natural fractures play a major role in well production.
When stimulation and development strategy began focusing on the Maraca group, a number of matrix stimulations were performed, most using coiled tubing (CT) at low pumping rates and volumes. The first few treatments used 15% hyrodochloric acid (HCl), but the acid system was switched quickly to an organic acid blend (13% acetic and 9% formic) because of the high reactivity of the HCl and its tendency to form sludge after contacting the asphaltenic Maraca oil. These matrix treatments had modest results, and the gained productivity was lost after a few months of production.

Acid Fracturing With Organic Acid
Acid fracturing was considered as an alternative to stimulate Maraca wells. Not only would acid fracturing increase well productivity, but it also would help retain the generated conductivity for a longer time period. Acid fracturing is a stimulation technique where acid, usually HCl, is injected into the reservoir at fracturing pressures. As the acid flows along the fracture, the fracture face is dissolved in a nonuniform manner, creating conductive or etched channels that remain open when the fracture closes. The effective fracture length is a function of the type of acid used, the acid reaction rate, and the fluid loss from the fracture into the formation.
Acid fracturing was preferred to hydraulic fracturing because proppant cleanout in a sour well with CT required operational and safety resources not yet in place. Additionally, the high conductivity of an acid-etched fracture made acid fracturing a more attractive technique if comparable fracture lengths could be achieved.
Achieving True Reservoir Stimulation in Deepwater Horizontal Sandstone Wells
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 95826, "Achieving True Sandstone-Reservoir Stimulation in Deepwater Horizontal Wells," by A. Mendez, SPE, BJ Services Co.; L.F. Neumann, SPE, and E. de Almeida Pinto, Petrobras; and R. Torres, SPE, R. Farias, SPE, and M. Acosta, SPE, BJ Services Co., prepared for the 2005 SPE Annual Technical Conference and Exhibition, Dallas, 9–12 October.
In offshore horizontally completed sandstone wells, an acid job usually is pumped to remove filter cake. When these wells are acidized with a hydrochloric (HCl)/hydrofluoric (HF) acid mixture, the resulting skin values usually are positive. An improved HF acid system (IHF) was introduced that uses an organophosphonic acid complex to control HF generation and to reduce potentially damaging secondary and tertiary precipitates. The full-length paper describes the results and case histories of field treatments that resulted in truly stimulated wells with negative skin.

Introduction
Production began in the Campos basin offshore Brazil in the early 1970s. Since then, more than 40 oil fields have been found in water depths between 260 and 7,800 ft. The most-prolific reservoirs are late Albian to early Miocene siliciclastic turbidites. These reservoirs are developed with horizontal and high-angle wells drilled into poorly consolidated reservoirs. The deepwater subsea wells must be designed to allow high production rates, typically more than 10,000 to 15,000 BOPD, with lifetime completions to avoid costly interventions.
Campos basin reservoirs were responsible for approximately 1.2 million BOPD in 2002, almost 83% of total Brazilian production, and are expected to produce 1.6 million BOPD by the end of 2005.
Sand control is required for wells in sandstone reservoirs that are poorly sorted medium-to-fine sands. These wells need to be completed with a package that includes premium screens in the horizontal section. To pump the gravel throughout the horizontal section effectively, a fluid composed of xanthan gum and calcium carbonate is used to create a filter cake and leave the formation stable.
Injector wells are completed in the same way as producers except an acid treatment is required to remove the filter cake and drilling residues remaining in the very-near-wellbore vicinity. Most injector wells are treated with the common HCl/HF mixtures.
Laboratory core flow tests were performed with core plugs from two different fields in the Campos basin. Tests compared results of treatments with several different acid blends. Results demonstrated that the IHF is capable not only of removing the filter cake but also of stimulating the formation more than the regular HF acid mixture (RHF). After laboratory tests were concluded, the IHF was field tested in two wells with a stimulation tool run with the gravel-pack tool in a single trip.