bluuebunny/crossref_metadata_2025_split huggingface dataset:
Production Enhancement in a Brownfield Redevelopment Plan
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 101491, "An Approach for Production-Enhancement Opportunities in a Brownfield Redevelopment Plan," by Antonio Cuauro, SPE, Schlumberger; Mohd Izat Ali, SPE, and Maharon Bin Jadid, SPE, Petronas Carigali Sdn. Bhd.; and Ekrem Kasap, SPE, (now with Shell E&P) and Torsten Friedel, SPE, Schlumberger, prepared for the 2006 SPE Russian Oil and Gas Technical Conference and Exhibition, Moscow, 3–6 October.
The Betty oil field was discovered in 1968 and has produced since 1978. With the objective of rejuvenating the asset, a multidisciplinary optimization team was built. The standard practices to evaluate production-enhancement opportunities include logging, nodal analysis, and well-engineering technologies. Usually, the older the field, the more challenging it is to achieve additional reserves. The full-length paper outlines an integrated approach for achieving these objectives, reducing the risk associated with the various enhancement alternatives.

Introduction
Brownfields have been defined as mature fields with declining production or at the end of their productive lives. Such fields contain resources that are needed by the countries they belong to and by the world economy. These brownfields generally are more than 30 years old and account for 67 to 72% of world production.
The Betty field was discovered in 1968 by the Betty-1 well, 25 miles offshore from Lutong, Malaysia, in the Baram Delta. A 24-slot drilling platform was installed in 1978, from which nine development wells were drilled. Two other structures house the separation facilities and a flare boom.
Three "revisit" campaigns were con-ducted on the Betty field. The first, in 1984, drilled five additional wells. The second campaign, in 1988, drilled 10 additional wells and worked over two existing wells. The third revisit was in 1994, to sidetrack four wells. There are eight reservoirs that have been targeted and produced. All of the wells are dual-string completions with two or more perforated intervals.
With the objective of rejuvenating the field, Petronas Carigali and Schlumberger joined forces to improve recovery from this mature field. A multidisciplinary team was assembled, and the collective approach to meet this objective focused on engineering and geology. Production enhancement involves several techniques to improve well performance, such as fracturing, acidizing, perforating, and artificial lift. The way to achieve the maximum productivity of a well is determined by the quality and quantity of data for that well.
Because field-development plans involve multiple objectives, the full-length paper details the well-engineering part, focusing on production-enhancement strategies. Determination of the estimated ultimate recovery (EUR) and the location of these reserves used both numerical simulation and nodal analysis, which are key to this integrated approach. The integrated approach was used to reduce uncertainties and risks associated with proposed activities.
Reviving the Mature Handil Field: From Integrated Reservoir Study to Field Application
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 110882, "Reviving the Mature Handil Field: From Integrated Reservoir Study to Field Application," by Henricus Herwin, SPE, Emmanuel Cassou, SPE, and Hotma Yusuf, SPE, Total E&P Indonesie, prepared for the 2007 SPE Asia Pacific Oil & Gas Conference and Exhibition, Jakarta, 30 October-1 November.
The Handil field, discovered in 1974, is a giant mature oil field in the Mahakam Delta of Indonesia. Fieldwide production declined from 200,000 BOPD in the late 1970s to 12,500 BOPD in 2003. An integrated study on the largest gas-injection reservoir was performed to assess project performance. An intensive light-workover (LWO) campaign was launched, and three pilot wells, each with a different type of completion, were put on production successfully. Infill drilling and optimization of an enhanced-oil-recovery (EOR) project also were implemented. Fieldwide production increased to 23,000 BOPD.

Introduction
As Fig. 1 shows, the Handil field comprises 555 unconnected accumulations (reservoirs) in structurally stacked and compartmentalized deltaic sands. The reservoirs are trapped by the Handil anticline, which is cut by a major impermeable fault dividing the field into two compartments: north and south.
The reservoirs are between 200 and 3500 m subsea and cover an area 10 km long by 4 km wide.
Three reservoir characteristics distinguish the field.Shallow zone: This zone is as deep as 1500 m subsea, with excellent permeability ranging from 200 to 2,000 md and with very strong aquifers that maintain the reservoir pressure at initial condition. However, the sands are poorly consolidated, requiring sand-control techniques.Main zone: This zone is between 1500 and 2200 m subsea, with permeability between 10 and 500 md. Most reservoirs had initial-gas caps, which have been pre-served to maintain the reservoir pressure, especially because the aquifers are not as strong as those for the shallow reservoirs. The sands are normally well consolidated; therefore, sand production is not an issue.Deep zone: This zone is below 2200 m subsea, contains mostly gas, and decreases in quality with depth to a permeability of several millidarcies.

Production History
To maintain production and reservoir pressure, water injection was started in 1978, which maintained the 160,000 BOPD production until 1985. Gas lift was introduced in 1979 and was implemented fieldwide in 1991. Infill drilling has helped maintain production. More than 350 wells have been drilled in the field, with an average spacing of 300 m. In November 1995, a lean-gas-injection project was initiated in five reservoirs. The project boosted the production of the five large reservoirs and altered the overall decline rate of the field. Therefore, the project was extended in 2000 to six other large reservoirs, which resulted in more than 25% of the field reserves being under a tertiary-recovery mechanism. In 2003, field production had declined to 12,500 BOPD.
Wellbore-Strengthening Technique for Drilling Operations
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 105809, "Further Development, Field Testing, and Application of the Wellbore- Strengthening Technique for Drilling Operations," by Giin-Fa Fuh, SPE, and Dave Beardmore, SPE, ConocoPhillips Co., and Nobuo Morita, SPE, Waseda U., prepared for the 2007 SPE/IADC Drilling Conference, Amsterdam, 20-22 February.
A significant increase in formation fracture resistance can be achieved as a result of a fracture sealing or plugging mechanism induced by a particle "screenout" effect resulting from the drilling fluid being loaded with an adequate amount of narrowly sized granular materials. Such an increase in formation fracture resistance is particularly valuable in helping to drill through depleted zones without losing fluid, strengthening the weaker formations that usually require additional casing strings for protection, avoiding lost circulation during cementing operations, and drilling high-angle well sections with high mud weights that normally would not be possible because of low formation fracture gradients.

Introduction
Lost circulation is perhaps the most costly mud-related drilling problem. Not only is rig time lost, but large volumes of expensive drilling fluids are lost to the formation. Lost circulation also can lead to severe well-control incidents. In response, several technologies referred to as "wellbore strengthening" (WS) are being developed to prevent or correct lost circulation. WS means that the breakdown pressure of the wellbore is greater after the treatment than before. These methods include use of special granular material, heating the wellbore, and use of rigid-plug-forming pills. The full-length paper focuses on a WS method that uses mud with special bridging and fluid-loss formulations.
In the mid-1980s, a joint-industry project (JIP) was conducted to determine why oil-based mud apparently caused a lower fracture gradient than water-based mud (WBM). Data from this JIP were analyzed, and it was determined that they did not fit ordinary fracturing models of the time. These researchers noted that certain lost-circulation materials (LCMs) actually seemed to increase the pressure required for fracture propagation to more than what was seen with untreated drilling mud. They conducted laboratory tests outside the JIP to verify their observations. The result was the development of a loss-prevention material (LPM) that was found to inhibit the extension of a fracture tip.
LPM was tested in the field several times and was quite successful. It was able to increase the wellbore break-down pressure in several cases, and subsequent application of the technology has allowed a casing string to be skipped in several cases. The technique affects only the near-wellbore break-down pressure, not the far-field fracture gradient.
Wellbore Strengthening in Shale
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 110713, "A New Treatment for Wellbore Strengthening in Shale," by Mark S. Aston, SPE, Mark W. Alberty, SPE, and Simon Duncum, BP plc, and James E. Friedheim, SPE, and Mark W. Sanders, SPE, M-I Swaco, prepared for the 2007 SPE Annual Technical Conference and Exhibition, Anaheim, California, 11–14 November.
The full-length paper demonstrates that wellbore strengthening in shale is feasible. A treatment pill was developed in the laboratory and field tested successfully at a US land-based location. The treatment consisted of a blend of particulates (known as stress-cage solids) and proprietary crosslinked gelling polymers that set with time. Properties of the system such as compressive strength, adhesion to shale, and sensitivity to temperature and pressure were evaluated. Modeling work was conducted to engineer the size and concentration of bridging solids required.

Introduction
Drilling in depleted zones, or intervals where high-pressured formations are interbedded with normally and abnormally pressured layers, has created the need for these strengthening technologies. The goal is to increase the fracture resistance of weaker formations and thereby avoid mud losses, wellbore instabilities, and the potential loss of the drilled interval. The primary consequences of these undesired events are an increase in nonproductive time and associated costs. In addition to avoiding these problems, the economic benefits that wellbore strengthening can provide are the possible elimination of a casing string or, more importantly, the ability to reach deeper reservoir targets.
One of the most popular wellbore-strengthening technologies is inducing an increase in wellbore stresses by use of sized-particulate additions to the drilling fluid. The common name for this approach is "stress caging." The principle is to increase the hoop stress around the wellbore by using fractures to cause stress changes in the rock. These fractures would be held open with bridging material, thereby creating the stress-cage effect, or strengthening of the wellbore. This bridge of particles across the mouth of the fracture must have low permeability to provide pressure isolation of the fluid in the wellbore from that in the fracture, thus preventing any further fracture elongation. The degree of stress caging relative to the native stresses is a function of both fracture width and radius and the rock properties (i.e., Young's modulus and Poisson's ratio). To achieve this effect, the proper type, size, and amount of loss-prevention material (LPM) must be used. Using the stress-cage concept and associated factors, drilling fluids can be designed to maximize this strengthening effect and minimize losses and other problems encountered when drilling significantly above the fracture gradient. In fact, use of these LPMs for wellbore strengthening has led to several complementary technologies.
Techbits: Technology Strategies Highlighted at Norway Conference
Authors: Moon Ted 
Published: February 2015

Techbits
From 15 to 16 October, more than 120 oil and gas professionals converged in Bergen, Norway for the fourth SPE Norwegian Petroleum Technology Conference (PTC). The conference, which was held in conjunction with Norway's Offshore Technology Days Exhibition, allowed managers, engineers, and business development planners to discuss how Norway plans to maintain its status as a global energy technology leader and incorporate innovations from companies big and small, far and wide.
"The conference was really focused around StatoilHydro's dominant role in the Norwegian oil and gas industry and how they plan to ensure continual development of new technologies and put them to use," said Jan Roar Drechsler, Chairperson of the PTC Program Committee and the SPE Stavanger section, as well as a Principal Engineer and Technical Representative for Completions with StatoilHydro. "In the past [prior to the merger of Statoil and Norsk Hydro], there was a sort of competition between Statoil and Hydro to be first in the development of a new technology. There is concern that now some development programs, either within the company or with different partners, might be put aside or altered. People wanted to know how these would go on in the future."
The first two presenters elaborated on this concern by outlining the role of technology in developing the reserves on the Norwegian Continental Shelf (NCS) and the dangers of scaling back future technology development programs. Roy Ruså, Vice President of Technology for Petoro, discussed upcoming technology challenges for operators and service providers in his talk "Technology Critical—Do We Act Accordingly?" Ruså pointed out that the mature NCS province still has many significant business opportunities, but they are linked to even greater technical challenges, such as realizing remaining reserves from smaller prospects, reducing nonrecoverable reserves, and finding and developing new recoverable resources. He acknowledged StatoilHydro as the major driver of technology development on the NCS, but added that the company must continue making significant investments in R&D and increasingly diversify its portfolio of production solutions by pulling in more technologies from other industries and geographic regions.
Technology Focus: EOR Performance and Modeling (January 2009)
Authors: Bai Baojun 
Published: February 2015

Technology Focus
Enhanced-oil-recovery (EOR) technologies have drawn increased interested because of the decreasing number of new-field discoveries, increasing number of maturing fields worldwide, and higher oil price, with the oil price peaking above USD 145/bbl in July 2008. It is more important than ever to understand lessons learned from past EOR applications and to develop new technologies and methods. More than 200 papers on EOR were presented at various SPE conferences in 2008. The EOR feature is split this year: EOR Performance and Modeling herein and EOR Operations in June. I categorized EOR papers for this feature into the following seven technologies.Wettability-alteration methods: surfactant imbibition for carbonate reservoirs, low-salinity waterflooding for sandstone reservoirs, and "smart water" for carbonate reservoirs.Chemical-flooding methods for conventional light oil: polymer flooding, polymer/surfactant flooding, alkaline/surfactant/polymer flooding, and surfactant-micelle flooding.EOR methods for heavy oil: steamflooding, in-situ combustion, steam-assisted gravity drainage, surfactant-alternating-gas, gas-assisted gravity drainage, thermal-assisted/gas-assisted gravity drainage, and alkaline/surfactant/polymer and alkali/surfactant flooding.Gas injection and CO2 sequestration: CO2 miscible and immiscible flooding, water-alternating-gas injection, and CO2 EOR and sequestration.Conformance control: gel treatments and foam flooding.Diagnosis and evaluation of EOR applications: seismic method, tracer injection, and mathematical modeling for reservoir heterogeneity and for induced fractures caused by water injection.Other EOR methods: in-situ seismic stimulation, microbial EOR, electrical EOR for heavy oil, and others.
The papers that I selected for this feature fall into the first four categories.
EOR Performance and Modeling additional reading available at the SPE eLibrary: www.spe.org
SPE 113304 • "Analysis of the Wettability-Alteration Process During Seawater Imbibition Into Preferentially Oil-Wet Chalk Cores" by L. Yu, University of Stavanger, et al.
SPE 113417 • "Residual-Oil Saturation from Polymer Floods: Laboratory Measurements and Theoretical Interpretation" by Chun Huh, SPE, University of Texas at Austin, et al.
SPE 113985 • "Evaluation of Manson Lease Oil Field for Improved-Oil-Recovery Process" by J.S. Tsau, University of Kansas, et al.
SPE 117607 • "Experimental Analysis of CO2-Sequestration Efficiency During Oil Recovery in Naturally Fractured Reservoirs" by J.J. Trivedi, University of Alberta, et al.
SPE 111403 • "EOR Methods To Enhance Gas/Oil Gravity Drainage" by P.M. Boerrigter, Shell, et al.
SPE 115204 • "Dynamic Induced Fractures in Waterfloods and EOR" by P.J. van den Hoek, Shell, et al.
Technology Focus: Well Control (January 2009)
Authors: Barnett David 
Published: February 2015

Technology Focus
In the last 6 years, the rig count has more than doubled from approximately 1,600 rigs in 2002 to more than 3,500 rigs operating worldwide in 2008. This phenomenal growth has been supported by increasing oil prices that have gone from less than USD 20/bbl in January 2002 to almost USD 146/bbl in July 2008 before falling off drastically in the following weeks. Assuming normal staffing and crew-rotation requirements, more than 30,000 people were needed to operate the 1,900 rigs that were added to the fleet during this period. Experienced personnel are spread thin as new hires are brought onboard to staff the rigs. This influx of new personnel into the industry created the additional burden of needing to train the new hires in the fundamentals of well control. It also makes it necessary to train an increasing number of personnel at the supervisory level as they advance to fill new positions.
Most people agree that the rig crew is the first line of defense against well-control problems. They are the "boots on the ground" that are charged with recognizing the first signs of impending trouble.
On the other end of the spectrum is the increasing number of operator and service-company personnel who are focused on advancing basic well-control principles to accommodate deeper, higher-temperature wells by use of exotic oil-based drilling fluids and by use of various methods of managed-pressure drilling.
The advanced well-control theories are supported by increasingly sophisticated computer models that account for numerous physical changes that become significant only at the elevated pressures and temperatures and increasing depths associated with these extraordinary wells. Interestingly enough, advanced well-control modeling is finding an increased number of uses in less-extreme wells and actually is assisting with teaching the fundamentals that apply to the broader class of wells.
The monumental tasks of training new personnel, training more personnel to higher levels of competency, and developing models to handle the extraordinary drilling environments accurately are all being met with surprisingly good results.
Developments in well-control modeling are providing useful insight into actual downhole conditions and fluid behavior that enables making much better decisions—both in planning and in actual well-control events.
Well Control additional reading available at the SPE eLibrary: www.spe.org
SPE 112761 • "Simulations Comparing Different Initial Responses to Kicks Taken During Managed-Pressure Drilling" by Asis K. Das, SPE, Blade Energy Partners, et al.
SPE 115019 • "Validation of Blowout-Rate Calculations for Subsea Wells" by P. Oudeman, SPE, Shell
SPE 113842 • "RFID Actuation of Self-Powered Downhole Tools" by P.M. Snider, SPE, Marathon Oil Company, et al.
Shared Vision (February 2005)
Authors: Paccaloni Giovanni 
Published: February 2015

SPE produces a number of publications, including magazines such as JPT and several peer-reviewed journals. Starting this month, a new magazine is added to the list—The Way Ahead. This magazine is being written by young SPE professionals mainly for the young segment of our membership (roughly 20,000 students and young professionals), but should certainly be of interest to other sectors (educators, managers, etc.) and to senior professionals willing to listen to the voices of their younger colleagues.
During my many visits with top executives of E&P companies worldwide, the subjects of young professionals and the future of the energy industry frequently arise. How do we keep young professionals motivated? How do we retain newly hired talents? What can SPE do to help the industry train and develop the young, both personally and professionally?
It is not new to our readers that I see the role of young professionals as absolutely central to our industry’s vitality. They are the bridge between students and senior professionals, representing the real key to the future of our industry. Since we all see this future as extremely complex and challenging, we need to do our best to provide all the possible support to this crucial category of individuals today. If we do not, we might face irreversible problems tomorrow. This is why the SPE Board recently approved the launch of The Way Ahead, and supports other young-professional initiatives.
Among the new young-professional initiatives is the very significant eMentor program. The goals of this program are (1) to increase the value of SPE membership to students and young members within the first 5 years of their careers and (2) to engage more experienced members in SPE and provide them with an avenue to “give back” to their profession. Young professionals would benefit from the contact with a more experienced professional, who could give career advice on the day-to-day issues facing them in the workplace. The eMentor program will use information technology to remove the limitations of physical proximity, thus transcending geographic boundaries and time constraints. SPE is creating a mentor database on SPE.org to match mentors and mentees. Prospective mentors will fill out an application that includes information about their education, experience, areas of expertise, and why they want to be a mentor. This program will be underway within the next few months.
Other programs/initiatives for young professionals include an annual Young E&P Professionals Workshop. The second international workshop for young professionals takes place this month in Scheveningen, The Netherlands, following a successful first meeting last year in Stresa, Italy. This event is poised to become a classic annual appointment for our young professionals, and a true benchmark of quality and creativity. I urge all young champions around the world not to miss the next edition of this extremely rewarding initiative, which cements friendships among worldwide young talents and provides exciting opportunities to learn from others’ new ideas.