bluuebunny/crossref_metadata_2025 huggingface dataset:
Technology Tomorrow: Reserves Growth: Torturous and Tortuous
Authors: Long Roy
Published: February 2015

Editor's note: This is the fourth installment of a yearlong series designed to stimulate discussion in energy research and development. This article focuses on near-term resource potential and processes for developing technologies to successfully develop this potential. Comments on articles in the Technology Tomorrow series are welcome. Please send any questions, comments, or ideas to vik.rao@halliburton.com.

At the World Petroleum Congress in 2000, the U.S. Geological Survey (USGS) presented its World Oil and Gas Assessment, showing a global conventional reserves growth estimate (Table 1). The greatest significance of this estimate was the size. The U.S., in particular, is highlighted because the reserves growth estimate is more than twice the remaining reserves and at least comparable with the undiscovered resource estimate. As noted in the assessment, "In the U.S., which is one of the most intensely explored countries in the world, reserves growth is widely considered to be a major component of remaining oil and gas resources. It is hypothesized that reserves growth of similar proportions also could occur worldwide as exploration for new fields matures and the intense exploitation of existing fields becomes an increasingly viable approach to developing new reserves."

A number of arguments have been made regarding the potential weakness of that hypothesis, but the significant impact of reserves growth is becoming more accepted. Notable in this assessment, as in all resource assessments, is the lack of discussion of the technologies and practices required to develop these resources in a timely manner. The challenge lies in the details of how we get there.

The Torture

Despite the upside potential of reserves growth, the process of developing that potential can be quite painful without adequate technology to support development programs. Fig. 1 is a plot of development program costs in one of the most challenging environments in the world, the deepwater U.S. Gulf of Mexico (GOM), during the period before 2004 when oil and gas prices were beginning to rise. The driver for the cost estimates and overruns came from the days when deepwater drillships cost between U.S. $300,000 and $400,000 per day.

As bad an impact as an average 60% overrun might be on a $44 million AFE project, the real inhibitor of resource development in the GOM is the potential for spending more than three times the anticipated average AFE cost. This magnitude of risk might be referred to as "elephant torpedoes" in the deepwater search for elephant reservoirs with regard to the impact on exploration budgets. Today, those same deepwater ships cost closer to $500,000 per day, and the industry is charging forth again into deep water based on a $60+ per barrel "war chest," but with only limited advancements in new technologies since the early 2004 time frame to aid in risk reduction. Success this time obviously will depend on lessons learned and human resources.
Overview: Subsea Technology (August 2006)
Authors: Salies Jacques B.
Published: February 2015

Once again, OTC thrived with projects, new technologies, and presentations that met the highest standards and expectations. This year, boosted by the steady increase in oil prices—having surpassed U.S. $70/bbl—attendance reached 59,236, the highest since 1982. Attendees from more than 110 countries were able to exchange their expertise on the development of offshore resources in the fields of drilling, exploration, production, and environmental protection. Subsea technology, more than ever, was a key factor in the huge success of this "Engineering Celebration."

As such, it is the focus of the papers selected for this feature, by means of which JPT seeks to present state-of-the-art technology in the quest to find and produce offshore oil and gas. Highlights include the development of two gigantic fields in western Africa and Brazil. These two fields will provide invaluable knowledge on how to use floating production, storage, and offloading vessels in the Gulf of Mexico (GOM), our next technological frontier. Another highlight is the technical challenges and opportunities for subsea processing and boosting. Several companies are investing in these technologies, aiming at applying them in the North Sea, GOM, Brazil, and western Africa. Such technologies, when put together, will be able to tackle the water-production challenge and will allow the production of new heavier-oil discoveries; they also will enable development of long tiebacks for oil and will play an important role in the subsea-to-shore challenge.

The efforts of our industry to overcome challenges in the development of subsea fields are well evidenced by the "Spotlight on New Technology Awards" at this year's OTC. From the 13 new technologies recognized with the award, one was for subsea boosting and another for subsea separation. In the near future, most certainly, new- or old-field developments will adopt a combined solution of sub-sea processing and boosting. The benefits seem very clear.

Therefore, I am especially pleased to invite you to read this impressive collection of topics for their scope, content, and effect on the industry. I hope you enjoy it.

Subsea Technology additional reading available at the SPE eLibrary: www.spe.org

SPE 100662 "Scale-Inhibitor Testing for Multiphase Pipelines in a Subsea-to-Shore Development With a Closed MEG-Loop System" by E.N. Halvorsen, Hydro Oil & Energy, et al.

Available at the OTC Library: www.otcnet.org

OTC 17810 "NDP Review of State of the Art in Riser Monitoring: Lessons Learned and Experiences Gained," by M. Chezhian, Det Norske Veritas, et al.

OTC 18318 "Evaluation of Low-Dose Hydrate Inhibitors (LDHI) for a Long-Distance Subsea Tieback in Ultradeep Water," by A. Singh, SPE, Total E&P U.S.A. Inc., et al.
Albacora Leste Field - Subsea Production- System Development
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 18044, "Albacora Leste Field - Subsea Production System Development," by C.E.C.V. Longo, S.J.A. Neto, and M.T.R. de Paula, Petrobras; F.M. Lopes Jr., Technip; and C.A.F. Godinho, SPE, Prysmian, prepared for the 2006 Offshore Technology Conference, Houston, 1–4 May.

The Albacora Leste field-development plan comprises 30 horizontal wells tied back to a floating production, storage, and offloading (FPSO) platform moored by use of an innovative spread mooring system (SMS). All risers are flexible and installed in a free-hanging configuration. Environmental conditions and FPSO motion were factors in flexible-riser design. All flexible lines were anchored by means of torpedo piles. The full-length paper describes field development, including planning, design, qualification, manufacturing, and installation activities.

Introduction

The Albacora Leste field is in the deep north area of the Campos basin approximately 120 km off the coast of Brazil. Water depths in this field range from 800 to 2000 m, and oil densities range from 17 to 21°API.

The field development comprises 30 horizontal wells (16 production wells and 14 injection wells, three of which are in a piggyback configuration) tied back to a host FPSO, P-50 by flexible risers and flowlines. Bending-stiffener and top riser accessories development and qualification represented an important and challenging success factor for the project. Three test benches were designed and assembled to perform the long-term fatigue tests for the gas-export flexible riser and to validate the new concept of the stiffener hanging systems.

The FPSO will be moored in 1230 m of water by use of an innovative differential-compliance anchoring system. The oil, after treatment and storage on the FPSO, is pumped to a shuttle tanker. The produced gas then is cleaned and compressed, and a fraction of the total volume is used for power generation, gas lift, and internal consumption; the remaining volume is exported to shore by way of Platform PGP-1 in the Garoupa field, Campos basin.

During the design phase, continuous gas lift and electrical-submersible-pump (ESP) artificial-lift methods were selected as potential candidates for the wells. However, at the time of the design phase, an ESP that could handle the high oil flow rates expected was not available, so the decision was made to use continuous gas lift as the artificial-lift method for the production wells. The approved gas lift design strategy eliminated pressure-operated valves and adopted a very simple and reliable well completion that included a single gas lift orifice valve. A high-discharge-pressure gas compressor was installed topside to guarantee continuous gas injection through the orifice valve at normal well-operation conditions and kickoff.
A Parametric Study of Horizontal and Multilateral Wells in Coalbed-Methane Reservoirs
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 96018, "A Parametric Study on the Benefits of Drilling Horizontal and Multilateral Wells in Coalbed-Methane Reservoirs," by N. Maricic, SPE, Chevron Corp., and S.D. Mohaghegh, SPE, and E. Artun, SPE, West Virginia U., prepared for the 2005 SPE Annual Technical Conference and Exhibition, Dallas, 9–12 October.

The full-length paper attempts to identify the most appropriate drilling pat-terns for coalbed-methane (CBM) reservoirs of different thickness and with different characteristics. The comparison yardstick for this study is net present value (NPV). In this way, drilling cost is accounted for when comparing different horizontal and multilateral configurations. Dual-lateral, trilateral, quadlateral, and fishbone configurations were compared. Total horizontal well length as well as spacing between laterals (SBL) was studied.

Introduction

CBM Background. Coal represents an unusual reservoir rock because of its highly complex reservoir characteristics. Unlike conventional sandstone reservoirs where gas is found in a free state within the pore structure of the rock, the methane gas is adsorbed onto the internal structure of the coal, which allows a significant amount of gas to be stored in the coal rock.

A coal-seam system is a naturally fractured heterogeneous reservoir characterized by macropores (the fracture system, also known as the cleat system) and micropores (coal-matrix system). In general, the coal cleat system is orthogonal, with one direction cross-cutting.

CBM production depends on fracture spacing and fracture interconnection. If the cleat system is not sufficiently developed, gas production can be very difficult. This occurs as a result of the low porosity and permeability values of the matrix, making it almost impossible for gas to move from the matrix into the fractures. At the beginning, the coal system is in equilibrium and typically, water must be produced continuously from coal seams to reduce the reservoir pressure and release the gas. Gas from the coal can be produced only after initial system dewatering and lowering the reservoir pressure. The dewatering process can take anywhere from a few days to several months and depends on CBM-well configuration. Generally, water production declines until the gas rate reaches the peak value. This "time-to-peak-gas" is a critical parameter because gas production begins declining soon after reaching the peak.

Horizontal Wells. One of the main advantages of horizontal wells is that well direction, shape, and position can be controlled. With horizontal wells, an almost ideal well position can be determined and achieved with respect to principal permeability directions of the coal. Proper well positioning as well as borehole length drilled perpendicular to the main fracture system of the coal can contribute significantly to draining large areas.
Techbits: Symposium Discusses Talent, Technology, and Challenges
Authors: JPT staff _
Published: February 2015

"The Challenges and Excitement Ahead: Talented People and Evolving Technologies" was the theme of the SPE Saudi Arabia Section's Annual Technical Symposium held 7–8 May at Dhahran, Saudi Arabia. The symposium has become a central E&P technical gathering for regional and international professionals, providing a valuable opportunity for professionals in the industry and researchers in academia to exchange and disseminate knowledge.

Symposium Chairperson Saud Al-Fattah, giving his welcoming speech, noted "the importance of talent and technology in meeting the challenges and demands of an energy-hungry world." Expertise and state-of-the-art technology, he stressed, form a powerful combination for advancing engineering and scientific work to improve the discovery and recovery of energy reserves.

Keynote speaker Khalid A. Al-Buraik, Chief Petroleum Engineer, Saudi Aramco, discussed the symbiosis, or interdependent relationships, of people, technology, and energy in bringing economic development and an improved standard of living to the world.

Following this, 2007 SPE President Abdul-Jaleel Al-Khalifa spoke on unleashing the industry's potential. The oil industry, he noted, has served mankind for the past 150 years and must examine how it can sustain prosperous growth through the coming 50 to100 years. The pressing challenges, according to Al-Khalifa, include the impact of skepticism today about the level of reserves, security of supply, stability of demand, cost inflation, the changing industry landscape between international and national oil companies, climate-change issues, and the industry's human-resources scarcity. Due to a lack of critical mass in human resources, Al-Khalifa said, industry personnel focus 80% of their attention on immediate drilling and production issues and have at most 20% of their attention to give to the important concerns of reservoir recovery.

Citing recent SPE survey data indicating that only 57% of industry professionals are fully engaged by their work, Al-Khalifa noted the large potential that the industry could unleash by fully engaging all of its professionals. The key elements for achieving this include providing a work environment of fairness, trust, and integrity; improving leadership development; adopting a people-first business model; and mitigating the impact of cyclical business fluctuations on the workforce. The productivity improvement attainable through achieving these goals could be as high as 30%, Al-Khalifa said.

Joe Sandy, Vice President, Technology, Halliburton, spoke on the role of technology in maximizing hydrocarbon production. Sandy emphasized the importance that the eastern hemisphere will play in technology implementation over the next 5 to 10 years. Major drivers for this technology will be deep water, small reserves, difficult reservoirs, difficult hydrocarbons, sustainable development, and constraints on capital, human resources, supplies, and material.
Smart-Well Technology at the SACROC CO2 EOR Project
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 100117, "Application of Smart- Well Technology to the SACROC CO2 EOR Project: A Case Study," by J. Brnak, SPE, Kinder Morgan Production Company, and B. Petrich and M.R. Konopczynski, SPE, WellDynamics, prepared for the 2006 SPE/DOE Symposium on Improved Oil Recovery, Tulsa, 22-26 April.

Application of smart-field technologies to the SACROC Unit carbon dioxide enhanced oil recovery (CO2-EOR) project in Scurry County, Texas, was studied. A five-well pilot project in early 2005 demonstrated the ability of intelligent-well downhole flow-control valves to restrict or isolate the production of CO2 from breakthrough zones in production wells and to control the distribution of CO2 injection in injection wells. The objective is to reduce unnecessary cycling of CO2 between injectors and producers, improve sweep efficiency, increase oil production, and improve ultimate oil-reserves recovery. This is done with cost-effective, fit-for-purpose intelligent-well systems.

SACROC Field

The SACROC Unit in Scurry County, Texas, is the seventh largest oil field onshore in North America, with 2.8 billion bbl of original oil in place. Its main producing formation is the Canyon Reef, a Pennsylvanian-aged limestone carbonate and part of a reef complex called the Horseshoe Atoll. It is a highly heterogeneous formation. Permeability within a single well can range from less than 1 md to hundreds of millidarcies. Likewise, porosity can vary drastically. Net and gross thickness can change significantly over short distances. However, average reservoir properties are as follows.Depth = 6,700 ft.Thickness = 259 ft.Porosity = 7.6%.Permeability = 19.4 md.

SACROC CO2 EOR Project

The SACROC Unit was discovered in 1948 as the Kelly-Snyder field. The field produced under primary depletion with solution-gas expansion as the main drive mechanism. Reservoir pressure declined rapidly, and in 1952, the Kelly-Snyder and Diamond M fields were unitized. In 1954, the operator implemented a crestal waterflood in which water was injected along the center (the spine) of the field. In 1972, CO2 injection was initiated. With limited CO2 supply, the oil-production response to CO2 injection was limited. During water and CO2 flooding, H2S was introduced to the reservoir from sources outside the unit. As shown in Fig. 1, shortly after CO2 injection was initiated, the unit's oil production peaked with rates exceeding 200,000 BOPD. During the following decline, several projects were attempted to halt the decline, but they had little effect. In 1995, a CO2-flood pilot consisting of five-spot patterns was started. This pilot used large CO2-injection volumes at miscible conditions, and the decline of the unit's oil production was halted. In 2001, project acreage under CO2 flooding began to expand rapidly. In response, oil production increased to more than 31,000 BOPD.
Field Surveillance: Enhanced Monitoring and Smart Alarms Produce More Oil
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 102091, "A New Approach for Field Surveillance: Enhanced Monitoring Associating Smart Alarms To Produce More Oil," by A. Lentini and G. Fumia, Eni E&P; H. Malonga and F. Okassa, Eni Congo; and J.P. Le Cann and J. Lessi, SPE, Geoservices, prepared for the 2006 SPE Russian Oil and Gas Technical Conference and Exhibition, Moscow, 3–6 October.

Managing wells produced with electrical submersible pumps (ESPs) must take into account limited pump-run life and production losses from ESP failures and shut in wells. Monitoring production and pump parameters is common, but real-time monitoring systems enable improving production conditions with rapid access to data that allows engineers to plan effective and timely remedial work. A system was field tested at an unmanned platform of a brown field with producing wells that use ESPs. The advanced information provided to the decision makers resulted in early production recovery and improved well inflow and outflow performance knowledge.

Introduction

The evolution of information technology has provided various new tools and opportunities to help maximize oil recovery while optimizing operational costs. Real-time data can increase the asset value only if the associated information can be analyzed fully in a timely and effective manner. The technology described here uses automated "smart alarms." It is intended to exploit the potential in the huge amount of information available from real-time monitoring of wells having ESPs.

This surveillance system was implemented on an offshore satellite platform in Congo. The existing instrumentation was used and the data made available in real time to every location within the company's Congo network by use of terminal-server technology. During a first monitoring and optimization phase, an optimal setting was found for each well. Then, in a second surveillance phase, smart alarms were built to detect deviation from the optimal behavior by comparing current data with a signature specific for each well and based only on wellhead parameters.

Background

Data-collection systems can provide very large amounts of data from different sources. The drawback of such a situation is the risk of losing the relevant information because of data overload and the lack of appropriate, coherent, and consistent processing of these data. It is important to focus on parameters that are key to optimizing well production and avoiding production losses. If correctly processed, these parameters can be used efficiently to trigger alarms that can draw the operator's attention, enabling immediate appropriate action.

The first step is to define processing that, when applied to specific data, will detect abnormal well behavior. The second step is to implement software that uses the data to trigger alarms. This software relies on "smart logic" to avoid any false alarm caused by a non-relevant situation, such as a planned shut-in of the well.
Overview: Subsea Technology (August 2007)
Authors: Salies Jacques B.
Published: February 2015

Once again, OTC thrived with projects, new technologies, and presentations that met the highest standards and expectations. Boosted by oil prices, attendance reached more than 67,000, a 25-year high. Nearly 2,400 companies from more than 30 countries participated in the show. It was a great opportunity to exchange expertise in the development of offshore resources worldwide. Subsea technology, more than ever, was a key factor in the huge success of this "Engineering Celebration."

Last year I highlighted challenges for subsea processing and boosting. Today, I believe even more that the great technical challenges bring huge opportunities for subsea processing and boosting. Such technologies, when put together, will be able to overcome the water-production challenge and will enable the production of increasingly heavier oil discoveries. Also, they will enable development of long tiebacks for oil and gas and will play an important role in the subsea-to-shore challenge.

Aligned with these principles, this year I picked papers that describe solutions adopted for subsea-compression systems (Ormen Lange), and integrated subsea separation, boosting, and injection (Tordis). I also picked a classical subsea development (Dalia) with great learning opportunities for all. Another subject that has generated much attention is the all-electric subsea tree. It is a great innovation with impressive results. I hope that next year we will be able to see another paper with the learning experience of the first system.

Therefore, I am especially pleased to invite you to read this impressive collection of topics for their scope, content, and effect on the industry. I hope you enjoy it.

Subsea Technology additional reading available at the OTC Library: www.otcnet.org

OTC 18749 "The Tordis IOR Project" by Ann Christin Gjerdseth, FMC Technologies, et al.

OTC 18969 "Ormen Lange Subsea Compression Pilot" by Bernt Bjerkreim, Hydro, et al.

OTC 18819 "First Application of the All-Electric Subsea Production System—Implementation of a New Technology" by Laurent Bouquier, Total, et al. (See JPT, June 2007, page 52.)
Dalia Subsea Production System
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 18541, "Dalia Subsea Production System, Presentation and Challenges," by J.L. Lafitte, M. Perrot, J. Lesgent, J. Bouville, and S. Le Pennec, Total E&P Angola; P. Dahl, Hydro; and S. Lindseth, AKS, prepared for the 2007 Offshore Technology Conference, Houston, 30 April-3 May.

In 2002, the Dalia subsea production system was the largest subsea order placed with a single contractor in off-shore history. The production system had 71 wells, 71 drill-through horizontal trees, nine six-slot production manifolds, two workover systems, flowline-connection systems, and a complex control and chemical-injection system. Heat conservation and hydrate prevention were paramount concerns during the subsea-production-system detailed-design and construction phases.

Subsea Production System

Fig. 1 shows the general field layout with the 71 subsea wells and nine production manifolds and the flowlines, risers, and control umbilicals that cover a subsea footprint of approximately 100 km2.

Production-Well-Cluster Layout. Various layouts were examined during detailed design to find the optimum solution. A typical production-well cluster comprises the manifold with three wells on one side and three wells on the other, all connected by rigid jumpers between the Christmas tree and the manifold. When the manifold is in the center of a flow loop, rigid spools connect production flowlines at both ends of the manifold. If the manifold is at the end of a flow loop, a pigging loop is mounted on the open side of the manifold, permitting roundtrip pigging. The control umbilical essentially is daisy chained from one manifold to the next. The rigid jumpers are not in contact with the seabed but float approximately 2.5 m above it because of attached buoyancy aids.

Advances in directional horizontal drilling and the use of simplified completions have enabled the wells to be grouped in six-well clusters, which not only facilitates batch drilling, where necessary, but also reduces the number of subsea flowline and umbilical connections.

Water and Gas Injection. Similar to Girassol, the same single-line header design is used to bring water and gas to the relevant wells. Control umbilicals are laid adjacent to the flowlines with subsea distribution units (SDUs) connecting the trees by electrical and hydraulic flying leads deployed by a remotely operated vehicle (ROV).

Wellhead, Christmas Tree, and Tubing Hanger. Horizontal-Christmas-tree technology has been selected that is compatible with a 7-in. full-bore completion and permits an efficient sequence of operations, giving the possibility of batch drilling with a minimum number of rig moves. Additionally, the trees have the drill-through capability that for a light-architecture-type well, lets the tree be run before the blowout preventer (BOP). With the tree and BOP in place, the well then can to be drilled, cased, and completed.
Building Bridges: Reflections
Authors: Cobb Bill
Published: February 2015

President's column

My term as president ends at the SPE Annual Technical Conference and Exhibition next month. I am amazed at how quickly the time has passed. This will be my last column, and so I think it is a good time for a bit of reflection on the organizational and personal goals with which I began my term:

Promote new Petroleum Resources Management System (PRMS)—In a previous column, I talked about the development of the PRMS. An important update is that the PRMS served as a major basis for recommendations made in late June to the US Securities and Exchange Commission for rule changes to modernize their reporting requirements for oil and gas companies. Our Oil and Gas Reserves Committee is preparing comments to the Commission on their proposals that relate to PRMS. I presented a briefing about the PRMS at a roundtable session on reserves at the World Petroleum Congress in Madrid in early July.

Develop leadership in carbon capture and sequestration (CCS)—I appointed an expert committee to guide SPE in this important area and to promote technical information exchange on best practices and lessons learned relating to CCS. The committee provided an update to the Board in June on upcoming SPE events with sessions on CCS topics, as well as efforts to coordinate our activities with other engineering societies.

Support young professionals programs—Our young professionals have great momentum in organizing workshops and programs around the world. I spoke to young professionals, as well as students, in almost every country I went to. I am confident that our industry will be in good hands. I also spoke at the World Petroleum Congress on the importance of industry collaboration to ensure that we attract new talent to the industry.

Promote energy education outreach programs to pre-college students—SPE's new Oil and Natural Gas book represents a tremendous opportunity to educate teachers, parents, and students about our industry. I've given copies to company and government leaders, as well as section leaders, throughout my travels this year. We also continue our efforts to collaborate with other professional societies on career outreach, and hope to expand www.energy4me.org to offer geoscience career information as well.

Build bridges to universities to help alleviate faculty shortage—High industry demand for petroleum professionals is causing both an inflow of students and an increase in faculty vacancies in the US and elsewhere. To help address the faculty shortage, SPE has created an Adjunct Faculty Clearinghouse on www.spe.org to help academic departments publicize their faculty needs to industry. SPE also recently established 15 new fellowships for graduate students, who may choose a career in teaching.
Techbits: Marginal Fields Focus of Malaysian Workshop
Authors: JPT staff _
Published: February 2015

Techbits

The Malaysian island of Langkawi was the setting for an SPE Applied Technology Workshop (ATW) titled "Development of Marginal Offshore Fields" held 21–24 April. Fifty-six participants representing 36 organizations and 11 countries discussed the challenges in developing marginal fields and the current industry trends and technology employed to deal with complex geologies, challenging drilling environments, and infrastructure constraints.

Interest in this workshop was great, as increasing energy demand continues to push oil and gas prices to new highs, forcing producers to examine fields that might have been considered economically unfavorable just a few years ago. High energy prices have brought a series of new challenges that developers of marginal fields have been forced to consider, including higher development costs due to rising commodity prices; increased environmental concerns pushing higher standards; and resource constraints in the form of a limited number of engineers, fabrication yards, drilling rigs, and construction barges. The workshop's program committee, cochaired by Azmi Mohd. Noor of Shell Global Solutions Sdn. Bhd. and Rakesh Kumar Vij of Oil & Natural Gas Corp. (ONGC), framed the content with these issues in mind.

Three keynote addresses were given, the first by Chen Kah Seong, General Manager of Project Development for Petronas Carigali Sdn. Bhd. Chen's address titled "Challenges of Developing Marginal Fields" set the stage for the workshop, and was followed by the speech "Trends in Marginal Fields" by Rajendra Marathe, General Manager and Head of the Institute of Reservoir Studies, ONGC. Garth Taylor from the Australian Trade Commission gave the final keynote, titled "Regulatory Body Influence in Marginal Fields Development."

Development Uncertainties Discussed

A series of nine technical sessions followed, with Sessions 2 and 3 discussing how to effectively manage subsurface uncertainties, including uncertainties in quantifying hydrocarbons in place, and anticipating the range of reserves recovery and production profiles. Other topics in these sessions addressed the value of information management for reducing subsurface uncertainties, how to maximize value by employing optimum reservoir recovery processes, and the appropriate evaluation and planning methods for a particular marginal development. Various methods for modeling uncertainty were also presented, followed by portfolio ranking at both the field and basin level, with examples of how risk management methods were successfully applied in various fields around the world.
Facilitating Collaboration in a High-Tech, High-Risk Environment
Authors: Benwell Tom
Published: February 2015

Management

When most people imagine a high-tech business, they picture San Jose or Seattle, not Tulsa or Lafayette or Houston. Those who walk the hallways of the energy business know better. Oil and gas exploration and development has become a world of high technology. While drill bits, pipe, and supplies for the toolpushers are still at the core of the oil and gas business, executives increasingly must manage complex networks of new-technology providers, and of traditional oilfield services that have leapt into a new technological age.

Onshore exploration and development continues to push deeper, applying new science every step of the way. Offshore, rigs push from deep water into ultradeep prospects, demanding technological innovation. As the energy-finding climate changes and risks grow, the most successful operators and suppliers develop collaborative relationships to deploy new technologies, maintain supply chains, and gain access to technical resources. The pressure to maximize efficiency and get results is intense, even with prices at historic levels. Operators and suppliers are stretching their technical resources, forcing companies to selectively allocate their hardware, software, and personnel. When a supplier bundles services and equipment for a competitor's key project, it may contractually commit specific technical talent, making them unavailable to others for some period of time.

Resources continue to be consolidated into larger, more complex organizations through mergers and acquisitions. New corporate combinations often lose focus on the customer, becoming internally focused for a while after the consolidation. Operators are reducing the number of suppliers they do business with to reduce the expense of managing so many relationships. Some companies have adopted a policy to deal with no more than three vendors in each procurement category. Smaller suppliers and service companies weeded out in that process find it necessary to work as a subcontractor to a larger supplier in order to maintain their access to the business.

Even in its most traditional moments, the energy sector has understood the need for joint ventures and strategic partnerships, as well as the value of collaborative relationships. But as the industry evolves, so must its approach to collaboration. In a time of rapid change, companies cannot afford to have technology acquisition and application struggle through traditional internal layers of approvers, such as conventionally structured procurement groups and established operations leadership. It has never been more important for operators and sup-pliers to understand each others business, needs, processes, and potential, and find the most productive common ground. There are good reasons to begin facilitated discussions about new ways of working together.
Developing Subsea Facilities for the Roncador Field
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 19274, "Development of Subsea Facilities in the Roncador Field (P-52)," by Jose Mauricio T.G. Lima, Mariele Lima Kuppens, Paulo Ferreira da Silveira, and Pedro Felipe K. Stock, Petrobras, prepared for the 2008 Offshore Technology Conference, Houston, 5-8 May. The paper has not been peer reviewed.

The second phase, Module 1A, of the Roncador field, offshore Brazil, was developed with a large semisubmersible floating production unit (FPU). This paper explains the strategies adopted by Petrobras to overcome the challenge of starting oil and gas production at a water depth of 1800 m in a short period of time, which required starting the platform construction early, almost simultaneously with the design of the riser system.

Introduction

Campos basin is offshore Rio de Janeiro State, southeastern Brazil. It covers approximately 100 km2 ranging from 20 to 3400 m water depth (WD). Roncador field lies in 1500 to 1900 m of water in the basin and was discovered in 1996. Development of Roncador field was planned with four production modules. Module 1A comprises two phases of exploitation: Phase 1 began production in 2002 with floating-production-storage-and-offloading (FPSO) vessel Brasil moored in approximately 1300 m WD, to operate some of the wells temporarily. By the end of 2007, the second phase of Module 1A (Phase 2) started to produce to the FPU P-52, which has a total displacement 80,000 t, moored stage of development and knowledge, operational issues, and available resources (e.g., installation vessels). The semisubmersible platform was selected to mitigate the risks of riser development. However, the desire to start Phase-2 production 4 years later required designing and contracting platform construction before the riser system was defined.

Problems faced during qualification testing of flexible-pipe flowlines and risers for Phase 1 raised concerns about the capability of this traditional riser solution for applications in ultradeep water. Therefore, other riser concepts were assessed. The steel catenary riser (SCR) was determined as appropriate technology for the design WD. An in-house technical feasibility study confirmed the SCR as the primary gathering system, while the flexible riser remained an alternative requiring approval in a prequalification program.

The SCR system and flexible risers, after prequalification of the latter with full-scale offshore tests, were both included in the subsea bid for the construction phase. Even though some changes were necessary in the FPU to allow the use of flexible risers, all the provisions for SCRs were kept operational for contingency purposes in the future.
REACH and the HSE Case for Formate Brines
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper IPTC 11222, "REACH and the HSE case for Formate Brines," by Ylva Gilbert, SPE, Gaia Consulting; Adrian Nordone, Cabot Corporation; John Downs, Cabot Speciality Fluids; and Anu Vaahtera, Piia Pessala, and Tuomas Raivio, Gaia Consulting, originally prepared for the 2007 International Petroleum Technology Conference, Dubai, UAE, 4-6 December. The paper has not been peer reviewed.

Europe's largest single piece of legislation, Registration, Evaluation, and Authorization of Chemicals (REACH), went into effect on 1 June 2007. REACH requires manufacturers, importers, and users of chemicals to demonstrate that their products are safe to use for humans and the environment. There will be increasing pressure to substitute less-hazardous materials for chemicals perceived as potentially harmful. The legislation is expected to have a significant effect on the management and application of chemicals used by the oil industry in Europe.

Introduction

The new European chemical legislation, REACH, represents a major revision of European chemicals management, replacing some 40 existing European Union (EU) Directives and Regulations. An objective of REACH is to place the responsibility of demonstrating the safety of chemicals on the manufacturers, importers, and users of the chemical. At the same time, the aim is to minimize the use of animal testing and encourage the substitution principle. The legislation encompasses all chemicals or chemical substances, including oilfield chemicals such as drilling and completion fluids. The full-length paper details the effect that REACH will have on management decisions and compliance procedures related to ensuring safe use of chemicals.

Methodology

The work presented in the full-length paper is based on a review of the literature and legislation as it applies to oilfield well-construction operations using formate brines as example chemicals throughout the discussion. Where comparisons with traditional brines are made, the data mainly have been sourced from open literature, and there are many gaps. For the formates, the authors also have had access to previously unpublished test results from the manufacturers. The findings from the literature have been complemented with information on the practical challenges of meeting REACH requirements, gleaned from discussions with four major operators.

To set the scene, the following section introduces the case-study chemicals. This is followed by a brief overview of two means of ranking chemicals on the basis of regulatory data. REACH and its processes as well as the time frame of implementation are then presented, followed by an overview of data requirements to support REACH. The findings then are discussed from a management point of view, as illustrated with formate brines.
Reservoir Fluid Properties Measured Downhole
Authors: O'Keefe Michael
Published: February 2015

Technology Update

Over the years, oil companies have started recognizing that a disturbing number of reservoir- and production-management problems could be traced back to a single root cause—inadequate understanding of reservoir fluid properties. After performing detailed analyses and calculations, scientists and engineers were able to quantify the cumulative economic effect of these shortcomings in reservoir knowledge. This provided encouragement to pursue a solution, but the process was difficult.

Although it may seem obvious, a prerequisite to accurate reservoir fluid analysis is the ability to acquire a representative sample of downhole fluids. In the late 1980s, a promising piece of the puzzle was developed—a pumpout module that could be incorporated in modular formation-dynamics testing tools. Until this time, highly contaminated fluid samples had been the norm because previous formation-testing tools were a closed system, whereby invaded mud filtrate was produced into a segregated sample chamber before an unknown quantity of formation fluid could be sampled. The pumpout module enabled the field engineer to pump undesirable fluids from the formation—via the sample probe—directly into the borehole, ensuring sample acquisition was performed after the produced fluid had been cleaned up to lower levels of contamination.

However, a breakthrough came in 2006 with the introduction of a focused probe tool that consistently provided a formation fluid sample virtually free of contamination from the invaded drilling mud filtrate. By using dual pumps to withdraw both the reservoir fluid and the surrounding mud filtrate simultaneously into separate flowlines, the mud filtrate could be diverted into the borehole, while the relatively pure stream of formation fluid could be obtained for measurement and collection by the field engineer in real time.

Variety of In-Situ Measurements Enabled

Once it became possible to acquire a pure sample, representative of formation fluid in reasonable time under downhole conditions, a variety of real-time measurements became feasible. Advanced instrumentation was packaged by Schlumberger into its modular formation-dynamics testing tool to perform nine separate field-selectable measurements, characterizing and describing produced fluid to enable real-time downhole analysis. The technology package, called the InSitu Fluid Analyzer system, can measureHydrocarbon fluid composition (C1, C2, C3–5, C6+)Reservoir fluid gas/oil ratio (GOR)Reservoir fluid CO2Reservoir fluid densityReservoir fluid viscosityReservoir fluid pHReservoir fluid colorReservoir fluid fluorescenceReservoir fluid resistivity
Drilling Failure Costs Quickly Add Up
Authors: Berry Cliff
Published: February 2015

Management

Annual downtime during drilling or running casing is only marginally better than it was 20 years ago. Operators’ estimates suggest that drilling efficiency is approximately 50% when taking into account all rig activities from spud to completion, including running casing tubing.

Trying to estimate the cost of this is not straightforward, but if 50,000 wells are drilled each year worldwide, ranging in day-cost from USD 135,000 on land to USD 450,000 for a semisubmersible, or a drillship at USD 1 million, then the average daily cost could be approximately USD 250,000. For wells that encounter trouble, the average time lost per well is probably approximately 6 days, which would give average downtime costs of USD 1.5 million for each well. Stuck drillstrings are one of the major contributors to drilling downtime, and a common cause of sticking downhole is a failed centralizer. A conservative estimate is that, annually, 400 wells worldwide (less than 1% of active drilling operations) are affected by centralizer problems, at a probable cost of 400 times USD 1.5 million, or USD 0.6 billion.

With downtime attributed to centralization problems reaching that amount, industry improvement in this area is essential. Centralizers are relatively cheap, but when they fail because of damage, breakage, or simply getting stuck in hole due to insufficient fitting at the correct intervals, then they assume a consequential cost out of proportion to their price. Losses at this level would not be tolerated in other industries, such as the automotive, marine, or aeronautical industries. Why should the oil industry be different?

Most centralizer failures are caused by using an incorrect unit for the job. Every day someone, somewhere, is pulling casing and leaving debris in the hole for the simple reason that the wrong type of centralizer was used. The oil industry seems surprisingly tolerant of these failures.

Centralizers since the early 1950s have been of multipart design and construction, being either welded or interlocked and having hinges and pins to hold them together. That design has remained largely unchanged to this day. With vertical wells, this type of construction is ideal as the string is in tension and no radial loads are applied. However, these units were oversized to the borehole, had high start and drag forces, and were weak in restoring force. This type of centralizer is still a regular choice in the industry but it is the single largest contributor to downtime and overspend.

As the industry developed, and well trajectories and types changed, the demands on centralizer technology increased. Some wells now have extremely close tolerance casings, some are under-reamed, and many are horizontal. The gravity effects on casings in angular and horizontal wellbores have made radial and axial forces crucial factors.
Multiscale-Data Integration in Characterizing and Modeling a Deepwater Turbidite Reservoir
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 115305, "Multiscale- Data Integration in Characterizing and Modeling a Deepwater Turbidite Reservoir," by Livio Ruvo, SPE, James Doyle, Mauro Cozzi, Simone Riva, Paolo Scaglioni, and Giuseppe Serafini, Eni, prepared for the 2008 SPE Annual Technical Conference and Exhibition, Denver, 21–24 September. The paper has not been peer reviewed.