bluuebunny/crossref_metadata_2025 huggingface dataset:
Q&A with Jose Formigli
Authors: Formigli Jose , Donnelly John
Published: February 2015

Brazil's goal has been to reach energy self-sufficiency early this year. Is that goal still attainable?

Our target is to reach self-sufficiency, on a sustainable basis, during 2006, when Petrobras' domestic oil production will reach an average of about 1.9 million BOPD.

What are Petrobras' growth targets for offshore and onshore oil and gas production?

In the recent revision of our Strategic Plan, we forecast production growth of 8.1% per year, from 1.76 million BOEPD in 2004 to 2.81 million BOEPD in 2010 (Fig. 1). This growth will come mainly from deepwater fields in the Campos and Espírito Santos basins.

The onshore oil production comes from mature basins, relying on an important existing infrastructure. Onshore findings can come on stream at a fast pace, requiring low capital expenditure, which compensates for the decline of the mature fields. The corporate pro-gram named Revitalization of Fields with High Degree of Exploitation is focused on the identification of economically feasible opportunities for increasing the production of oil and gas and/or increasing the ultimate recovery. The focus is not only on onshore brown-fields, but also on offshore fields beyond the production peak. As a result of these efforts, we expect that the 2010 onshore production of oil and gas will be kept at the same level of 293,000 BOEPD attained in 2004.

What new offshore production has recently come on line or will start up in the near future?

Many offshore production systems started up at the end of 2005 or are scheduled to start up throughout 2006:Peroa-Cangoa gas field, in the Espírito Santos basin, is beginning production of 2.5 million m3/D through a shallow-water fixed platform.Floating production, storage, and offloading vessel (FPSO) P-50, located at the Albacora Leste field, started up in November 2005, with a production capacity of 180,000 BOPD.FPSO P-34, located at the Jubarte field, is expected to start production of 60,000 BOPD during the first quarter of 2006.The Manati offshore gas field in Bahia has a capacity of 6 million m3/d through a fixed platform and will start production in the second quarter of 2006.Golfinho I, in the Espírito Santos basin, will produce 40°API oil and has production capacity of 100,000 BOPD. It is scheduled to come on stream in mid-2006.The deepwater Piranema field in the Sergipe-Alagoas basin is scheduled to produce 20,000 BOPD of light oil using the pioneer concept of a cylindrical floater production and storage system. It will start operation in the second semester of 2006.
Technology Tomorrow: Carbon, Hydrogen, and People
Authors: Rao Vikram
Published: February 2015

Editor's note: This is the first installment of a new yearlong series designed to stimulate discussion in research and development. The Technology Tomorrow articles will be published every other month and vary in emphasis, covering topics as broad as R&D industry trends and as focused as improving reservoir recovery factors. This series is one of several actions being taken by the SPE R&D Advisory Committee to encourage R&D development and discussion. The target audience is the entire readership of JPT. We hope to create a forum that sparks discourse and ideas, including those ideas that may not be in the current mainstream of thought. Comments on the articles are welcome. Please send any questions, comments, or ideas to vik.rao@halliburton.com.

Two of the most pressing problems facing the oil and gas industry are the perceived shortages of oil and natural gas and an aging workforce combined with the inability to attract talent to the industry. The first is manifest in the price of oil worldwide, and that of gas in the consuming countries. Both of these are at unprecedented highs and, more importantly, are widely forecast to stay high for a number of years. Unlike the oil price shocks of the 1970s, this one is demand driven, and this time the world's workhorse producing fields are in the decline phase.

So, do we face a medium- to long-term prospect of shortages of oil, gas, and people? This article advances the belief—probably not. Energy molecules are plentiful; they are just in the wrong form or in the "wrong" place. Similarly, qualified personnel are available and not averse to working in the energy industry, they are just in places we do not source from enough. Much support can be offered for the first contention; the one regarding people relies on solid numbers and a dose of conjecture.

Unlocking the Potential

All energy-producing compounds comprise carbon (C) and hydrogen (H) in some proportion. Coal is at one end of the C/H spectrum, with the carbon-to-hydrogen ratio in excess of 8. At the other end is natural gas. Curiously, these two polar opposites are the principal sources of energy for electricity generation. The molecules in the middle are used for transportation and, for that purpose, need to be delivered in the form of light and middle distillates, gasoline, and diesel. Two unconventional sources of oil found in abundance are shale oil (more than a trillion bbl) and ultra heavy oil (also well over a trillion bbl). The former is in the form of kerogen, requiring thermal modification to yield useful oil, and the latter is a material that does not flow readily and, consequently, is difficult to produce and transport. It has C/H ratios in the vicinity of 8 and thus is many hydrogen atoms short of the needed light and middle distillates.
Management: Progress and Challenges for Health, Safety, and the Environment in Exploration and Production (February 2006)
Authors: Arscott Lyn
Published: February 2015

Introduction

A computer-based survey was taken of the program committee members of the first Asia Pacific Conference on Health, Safety, and Environment (HSE) in Oil and Gas Exploration and Production, which was held in Kuala Lumpur during 19–21 September 2005. The committee members, experts in their fields, were asked to express their opinions on the progress of the industry on HSE issues over the past 5 years and the effort that the industry should make over the next 5 years. This was the second time this survey has been conducted. The first time was at the SPE Seventh International Conference on HSE held in Calgary during 29–31 March 2004, and the results were reported in the July 2004 issue of JPT.1 The Kuala Lumpur results and the Calgary results are presented in the tables below. It should be noted that informal surveys were taken of the program committee members of the previous six SPE international conferences on HSE starting in 1991, but they were not in the same format as the two conferences mentioned above, so a quantitative comparison is not possible.

Methodology

The committee members were asked to complete a web-based questionnaire with the following questions:How would you rate the progress made by the industry in the following subjects over the past 5 years (excellent, good, moderate, poor, very poor)?How would you rate the effort that the industry should make in the next 5 years (much more effort, more effort, same effort, less effort, much less effort)?How would you rate the effort regulators should make in the next 5 years?How would you rate the effort that nongovernmental organizations (NGOs) should make in the next 5 years?

The method of scoring and ranking is summarized in the appendix. A summary of the status of the industry programs is shown in Table 1, with the full results in Tables 2–4.
Overview: Drilling and Cementing Technology (February 2006)
Authors: Dupuis Dominique
Published: February 2015

During 2005, the oil industry paradigm changed somewhat. The media highlighted doubt concerning world oil reserves expressed in time expectancy. Is it less than the sliding 40-year scenario? There are optimistic and pessimistic scenarios. During the year, demand and supply coincided. The oil prices increased drastically as a consequence of the growth of China, India, and other countries. On the other hand, environmental specialists have alarming forecasts with respect to the greenhouse effect and temperature increase because of CO2 accumulation. Initially, the capture of CO2 probably will lead to more wells being drilled. As a result of these contradictory parameters, the drilling industry has many challenges ahead to deal with instantaneous lack of oil and future complex developments.

The giant fields are reputed as discovered. Maybe the potential lies in some unexplored region (e.g., east Siberia), deep buried reservoirs (onshore and offshore), or better drainage of existing reservoirs improving the recovery factor to 65% or more.

To renew the reserves, the drilling community faces many challenges.

For deep reservoirs, in some instances ultradeep wells, those challenges lie in ultrahigh pressure, high temperature, and narrow mud-weight windows. Therefore, a new casing design (e.g., monobore) and new engineering and operation procedures will be required.

For enhancing the life of existing reservoirs, the technology of through-tubing completions opens new perspectives.

Cementing operations, often underevaluated, are of prime importance. Recent developments have led to a wider range of cement-slurry density, new well designs, and simplifying of operating procedures.

Coming back to basics, with respect to destruction of rock, let's dream: Why not a revolution using laser technology? Future generations of drillers will write case-history papers on laser-drilled wells. How soon—in 2050, 2030, maybe sooner?

Drilling and Cementing Technology additional reading available at the SPE eLibrary: www.spe.org

SPE 92194 "Maximizing Drill Rates With Real-Time Surveillance of Mechanical Specific Energy," by Fred E. Dupriest, SPE, ExxonMobil, et al.

SPE 95888 "Benchmarking Deep-Drilling Technologies," by S.W. Lambert, Schlumberger Consulting Services, et al.

SPE 96927 "Why Don't We Pump More Type I/II Lightweight Slurries?" by R.R. Myers, SPE, BJ Services Co.

Available at the OTC Library: www.otcnet.org

OTC 17459 "Drilling Underbalanced From a Floating Unit in a 1500-m-Water-Depth Exploratory Well: Planning, Equipment, and Rig Modifications," by A.C.V.M. Lage, Petrobras
Overview: Well Testing (February 2006)
Authors: Stratton Jay
Published: February 2015

Careful well-test design applied intelligently to exploration and development situations is the reality check for information that many times can only be inferred from other reservoir-evaluation tools. With drilling rigs in short supply and day rates at historic high levels, smart application of well-test technology may reduce costs considerably by use of short-duration openhole wireline-test equipment. Commerciality can be determined quickly and rigs moved on to the next objective or well. In contrast, extended well tests, conceived to prove a commercial hydrocarbon accumulation, may provide enough data to validate a reservoir description and clear economic hurdles without drilling an additional well—important for time-critical decisions on adjacent leases.

Many times in the operating environment, a petroleum engineer may use well-test results to provide a reality check and economical data acquisition for geophysicists, production geologists, and simulation engineers on one end of the organization and production operations personnel pushed to maximize well rates on the other end. Careful well-test planning and analysis can satisfy both extremes. Reservoir-characterization professionals can validate reservoir boundaries, pressures, and the accuracy of production history. Production operations can maximize production confidently in a miscible-gas flood without going below minimum miscibility pressure and compromising recovery. A delicate balance can be maintained with little or no production loss, allowing responsible reservoir management while maximizing rates and ultimate recovery.

With oil prices hovering around U.S. –60/bbl, there has never been a larger incentive to optimize well testing in exploration, development, and production environments. This month's selections show how relatively conventional testing procedures, applied intelligently, can accelerate development decisions. Deconvolution of real-time reservoir performance is always going to be an attractive goal in well-test analysis to eliminate production loss from conventional pressure-transient analysis. Use of multiple analysis techniques can be complementary to other reservoir-characterization methods. Advances in intelligent completions, permanent data-acquisition systems, and flow-measurement technology continue to entice petroleum professionals into devising innovative techniques for advanced well-test analysis.

Well Testing additional reading available at the SPE eLibrary: http://www.spe.org/

SPE 96026 "Determination of Optimal Window Size in Pressure-Derivative Computation Using Frequency-Domain Constraints," by Y. Cheng, SPE, Texas A&M U., et al.

SPE 94436 "Time-Lapse Production Logging and the Concept of Flowing Units," by O.D. Cortez, SPE, Centrica Energy, et al.

SPE 94018 "Application of Buildup Transient-Pressure Analysis to Well-Deliverability Forecasting in Gas/Condensate Reservoirs Using Single-Phase and Two-Phase Pseudo pressures," by M. Bozorgzadeh, SPE, Imperial College, London, et al.
Q&A with DeAnn Craig
Authors: Craig DeAnn
Published: February 2015

Editor's Note: In recognition of SPE's 50th anniversary in 2007, JPT is conducting interviews with several Society luminaries about their careers, their relationship with SPE, and the changes they have seen in the oil and gas industry and the Society over the past several decades.

As SPE's first female President, were there any special obstacles you had to overcome or challenges you faced?

When I first started in this industry, I was working on an offshore exploration project, and an engineer in my position needed to go offshore during well testing. But I was not allowed because there were no accommodations for women. When I was President of SPE, there were a few facilities I could not enter because I was a female.

How has the role of women in the oil and gas industry changed since you were SPE President in 1998?

There are so many women in the industry now in all positions. And the attitude now is that it is the norm to have women in the industry. Sure, it would be nice to have more, but it is such a change from when I used to be in meetings and there were no other women in the room. I cannot recall a single meeting that I have been in lately where there have not been several women in the room. I mean things have definitely changed.

What advice would you give women just entering or considering a career in the industry?

Build a diverse network of career coaches—other women, men, people in higher positions, peers in similar positions, and professionals within your company and in other companies. You will need a sounding board on a variety of topics. Advice is usually better when it includes a diversity of opinions.

How do you see SPE evolving or changing over the next decade?

SPE is truly international now. It was in the process of becoming more inter-national when I was President. In the future, I see SPE diversifying into more energy areas—doing more on liquefied natural gas, more on carbon capture, and more on unconventional oil and gas production. I also believe that usage of the Internet for information dissemination will continue to increase. And the use of volunteers' time will have to adjust—more of the work of SPE will have to shift to the SPE staff.

How do you see the industry evolving or changing over the next decade?

Demand for oil and gas will continue to rise over the next decade. To meet that demand, the industry will face more difficult technical challenges. As a result of limited access, there will be continued consolidation within the industry.

When I was just starting my career, it was pretty obvious to me that it was the financial end that was the real problem in the industry. I think the industry has now switched; everybody understands that they have a handle on the financial side now. But the main issues now are technology and geopolitics.
Effects of Long-Term Exposure to Ultrahigh Temperature on the Mechanical Parameters of Cement
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 98896, "Effects of Long-Term Exposure to Ultrahigh Temperature on the Mechanical Parameters of Cement," by D. Stiles, SPE, ExxonMobil Development Co., prepared for the 2006 IADC/SPE Drilling Conference, Miami, Florida, 21–23 February.

Long-term cement-sheath mechanical durability is critical to maintaining zonal isolation for the life of a well. Wells subjected to cyclic steam stimulation (CSS) undergo extreme temperature changes that cause substantial stresses on the cement sheath. Analysis models that are useful in predicting the failure potential of a cement sheath require input of cement mechanical parameters. The full-length paper presents a test methodology for measuring the mechanical parameters of five cement formulations after exposure to 645°F.

Introduction

The Cold Lake development in eastern Alberta, Canada, has been in operation since the mid-1980s. It is the largest in-situ heavy-oil recovery operation in Canada and one of the largest thermal heavy-oil operations in the world. Production of the heavy oil is by CSS, in which steam is injected into the reservoir above fracture pressure and a mixture of bitumen, gas, and water is produced from the same wells.

Historically within the oil and gas industry, the only concern with cement formulations at ultrahigh temperatures was chemical stability. The loss of compressive strength in Portland cement and increase in permeability at temperatures greater than 235°F was discussed in the literature as early as 1935. This phenomenon, commonly referred to as strength retrogression, is the result of morphological changes in the crystalline structure of cement when it is exposed to elevated temperatures. Preventing strength retrogression by addition of finely ground crystalline silica at a 35 to 40% concentration by weight of cement (BWOC) was discovered nearly 50 years ago and has been the industry standard ever since. All cement formulations used throughout the Cold Lake project have contained the recognized silica concentration.

Cement-sheath failure resulting from wellbore stresses received little attention before 1992. While there are distinctive differences in the mathematical models that have been developed, they all agree that sheath failure is a function of the stress states imposed on the wellbore and the mechanical parameters of the cement sheath and the surrounding rock. The stress states imposed on the wellbore by large temperature increases, such as those encountered during steam injection, have been recognized as sufficient to cause tensile cement-sheath failure.

The key mechanical cement parameters responsible for whether or not sheath failure will occur are Young's modulus, Poisson's ratio, and tensile strength. No measurements of these parameters ever had been performed on cement samples that had undergone long-term exposure to the ultrahigh temperatures encountered during CSS at Cold Lake.
Albacora Leste Field - P-50 FPSO Mooring System
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 18243, "Albacora Leste Field Development - FPSO P-50 Mooring- System Concept and Installation," by F.E.N. Brandao, C.C.D. Henriques, J.B. de Araujo, O.C.G. Ferreira, and C. dos Santos Amaral, Petrobras, prepared for the 2006 Offshore Technology Conference, Houston, 1–4 May.

The mooring system for the P-50 floating production, storage, and offloading (FPSO) vessel is an 18-line, partially compliant spread-mooring system, with 10 lines to the bow and eight lines to the stern. The mooring lines comprise polyester ropes and steel chain in a semitaut configuration. This project was the heaviest synthetic-line mooring system designed for a floating production unit.

Introduction

Since the late 1990s, free-fall piles, "torpedoes," have been used offshore Brazil. Initially, torpedoes were used to moor flexible risers to the sea bottom, then later to moor semisubmersible drilling rigs. In April 2001, the classification group Bureau Veritas certified a design called T-43 (a 43-tonne torpedo pile). These torpedoes were used to moor a deepwater drilling rig and the floating storage unit Avaré, a former 30,000-DWT tanker, installed in the Santos basin offshore Brazil.

The mooring analyses of the P-50 FPSO showed that the required anchor-holding power would be approximately 1000 tonnes and the use of a differentiated compliance anchoring system with polyester ropes would require the use of anchors with high vertical-holding capacity, such as vertical-loaded anchors (VLAs) or suction piles. VLAs had been used to moor semisubmersible floating production units, such as P-27, P-36, and P-40 in the Campos basin. However, for the holding capacity required to moor the P-50 (a 270,000-DWT tanker), three or four anchor-handling vessels (AHVs) with sufficient bollard pull would be required to embed the anchors in the soil. Experience with the P-43 installations showed that the required installation time could be much shorter with torpedo piles than with VLAs. In October 2000, development of a torpedo that could meet P-50 requirements began and resulted in the T-98 design (a 98-tonne torpedo).

P-50 Mooring System

P-50, a former very large crude carrier converted into an FPSO, operates in 1240 m water depth in the Albacora Leste field, Campos basin, Brazil. The heading of the unit is 208° from true north, and the mooring pattern is shown in Fig. 1.

The seabed has a maximum slope of 4°, and the deepest anchor was set at a water depth of 1384 m. Because flexible risers are connected to the FPSO, the mooring-system configuration was designed not to exceed the maximum horizontal offset and rotation limits around the vertical axis in the intact and damaged (one line broken) conditions. On the basis of the riser specifications and operating experience, the horizontal offsets were set not to exceed 10% of the water depth in the intact condition and 15% in the damaged condition. Each mooring line consists of studless chains and polyester ropes, designed for 25-year life.
Tow Methods for Deepwater Riser-Tower Transportation in West-of-Africa Environment
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 17892, "Novel Tow Methods for Deepwater Riser-Towers Transportation in West-of-Africa Environment," by R. Di Silvestro, F. Casola, G. Fatica, A. Mameli, and A. Prandi, Saibos SAS, prepared for the 2006 Offshore Technology Conference, Houston, 1–4 May.

Riser towers are characterized by very low service-fatigue damage in deep-water fields with floating production facilities. However, transportation from the fabrication yard to site can be of concern. This phase can use a significant portion of the allowable fatigue damage. Longer tow distances use more of the allowable fatigue damage. Two tow configurations that minimize the fatigue damage and allow longer tow distances are presented.

Introduction

The use of riser towers in deepwater fields west of Africa has increased in recent years. In addition to low service-fatigue damage, high thermal performance and the ability to accommodate many risers and umbilicals are advantages over the more traditional riser concepts. The presence of a floating production, storage, and offloading (FPSO) vessel is not required before installation of the tower, improving the installation sequence and reducing the time to first oil production after the FPSO arrives.

Transportation of the tower from the fabrication yard to the field is a critical operation that consumes much of the allowed fatigue. Management of towing is a key aspect in this phase of the oil industry driven by the growing distance between fabrication and installation sites as new fields are found in deeper waters.

Two tow methods were developed for transporting the riser tower developed in line with the bundle-hybrid-offset-riser (BHOR) concept. Both surface and submerged configurations were considered to mitigate the dynamic-fatigue response of the tower to wave periods and facilitate tow operation lasting many days.

BHOR Overview

The BHOR is based on the steel-hybrid-riser concept and is a freestanding assembly with several risers in a bundle configuration. In Fig. 1, the assembly is top tensioned by a buoyancy tank and anchored to the seabed by means of a gravity-skirted foundation. The connection of the bundle main section (BMS) to the seabed foundation is made by means of a mechanical flexible joint similar to that used for a tension-leg-platform tendon that is able to accommodate the small angular excursions of the bundle with a limited stiffness. A similar connection is used to connect the buoyancy tank to the top part of the tower. The buoyancy tank is a standalone structure that is installed after the upending of the BMS and docking it to the foundation. The buoyancy-tank structure is derived from the typical pressure-vessel design. The schedules for fabrication and installation of the bundle and the buoyancy tank are independent.
4D-Pressure Pilot Determines Well Spacing in Tight Gas
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 102745, "4D-Pressure Pilot To Steer Well Spacing in Tight Gas," by E. Quint, M. Singh, SPE, P. Huckabee, SPE, D. Brown, C.B. Brake, J. Bickley, and B. Johnston, SPE, Shell E&P Americas, prepared for the 2006 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 24–27 September.

Obtaining accurate formation pressures in microdarcy rock is a formidable challenge. However, these pressures provide the best data to identify unique reserves. They help to determine the drainage areas as well as appropriate well spacing for tight gas reservoirs. A 4D-pressure pilot was designed and installed to measure pressure drop at two observation wells equipped with pressure gauges. The pressure gauges enable pressure monitoring along the wellbore (in space) and over time, hence the name 4D-pressure pilot.

Introduction

The Pinedale field, in the Green River basin, Wyoming, is an example of a tight-reservoir gas accumulation. The field is a northwest/southeast-trending, doubly plunging, asymmetric anticline, 35 miles long and 6 miles wide, with the west flank bounded by a buried, high-angle, east-dipping thrust fault having as much as 660 ft displacement.

The discovery well for the field was drilled in 1939. Sporadic drilling and evaluation of the field continued for almost 60 years. All early wells encountered significant gas shows but low production rates because of poor reservoir quality and limited completion intervals.

Most of the wells in the Pinedale field have been on production for only a few years, and the drainage area has not been established. Therefore, the appropriate well spacing has not been determined. Most tight gas fields in the area started with 40-acre well spacing and were downspaced subsequently to 20-, 10-, or 5-acre spacing. Getting the well spacing and pattern correct early in the development is essential for cost-effective exploitation.

In a layered model, the formation pressure at 10- and 20-acre offset locations declined by hundreds of psi if the sands were connected. Conversely, there was no pressure change if the sands were totally isolated. Therefore, a better test to determine well interference and optimal well spacing was to drill a pilot hole and observe the pressure rather than production changes in individual sand packages in one well while producing the other.

To achieve optimal well spacing for a field, models were built and tested against the observed pressure measurements. If the model predicted pressure changes accurately, it could be used to optimize drainage patterns. The drilled wells were removed from the model, and the acreage was developed in several patterns, after which the pattern with the highest net present valve was chosen and implemented.
E&P Production-Information Management: A Tale of Two Types of Data Integration
Authors: Pattanaik Manas , Ashish Ashutosh
Published: February 2015

Management

What is the current production? Which production area/well should we concentrate on? How is the current production measuring up vs. past budgeted/forecasted numbers? Questions like these keep everyone from lease operator to production manager awake at night and busy during the day.

Technology advancements have made it possible to gather more data both in terms of quantity and type, all the way from bottom hole to sales meter. This has inundated the E&P users with an exponential increase in multiflavored data. Typically, these data are collected by different petrotechnical applications and stored in their respective repositories or in someone's local computer, often in an isolated fashion. Left in their respective silos, these data are fragmented and provide limited information or intelligence about important production/operational metrics such as the well production or the lease operating expenses (LOEs) of a well. As a consequence, the users are inclined to adopt temporary methods or localized solutions to piece together the information they need, producing two very undesirable results. First, users spend a lot of administrative time to mine data, extract the needed information, and reconcile differences when errors occur. Second, a number of ad hoc processes, tools, and offline databases that suit the individual preferences, but not necessarily representing an enterprise standard, mushroom in the organization. Therefore, because definitive and accurate production information evades the business users, they are often kept away from performing the more desirable value adding E&P functions. In addition, inefficiencies are created, such as low employer productivity, high cost, and poor knowledge sharing.

Fig. 1 is an illustration of how data from multiple sources are typically combined to provide E&P production and operation information in the absence of an integration platform.

To address the problems outlined, it is important for E&P companies to adopt an integration approach that relies on an integrated thinking. This will enable them to manage and use their production and operations data effectively. But before we describe the approach, it is worthwhile to define integration in the broader E&P context and look at factors that drive the need.
Drillstring Technology for World-Class Extended-Reach Drilling
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 18512, "Drillstring Technology Vanguard for World-Class Extended-Reach Drilling," by M.J. Jellison, SPE, and R.B. Chandler, SPE, Grant Prideco; M.L. Payne, SPE, BP; and J.S. Shepard, SPE, GlobalSantaFe, prepared for the 2007 Offshore Technology Conference, Houston, 30 April-3 May.

Projects that will expand the extended-reach-drilling (ERD) envelope are in the planning stage in various parts of the world. Drilling engineers no longer are wondering if 50,000-ft ERD wells can be drilled but how this can be accomplished safely and efficiently. It has been estimated that the last 10% of the drilled interval can account for 50% of the total drilling cost. The full-length paper discusses the latest drillstring technologies that are essential to achieve the ERD targets planned for the future.

Advanced Material Technologies Industry publications have presented the idea of using nonsteel drillstrings for reduction of torque and drag loads in extended-reach (ER) wells. Other torque- and drag-reduction and management tools and techniques that have proved successful are lower in cost, thus being the preferred methods for meeting current ER torque and drag challenges. The competition of these alternative technologies has inhibited the development of commercially available nonsteel drillpipe.

The direction toward longer-departure ER wells has led to increased consideration recently for commercially available nonsteel drillpipe. Generally, three advanced materials should be included in this consideration—carbon-fiber-based composites, titanium, and aluminum. Each has been used in drillstrings with varying degrees of success. Each material has strengths and weaknesses relating to its use for drillpipe to drill ER wells and other critical applications such as ultradeep drilling and deep water.

Carbon-Fiber-Based Composites.

Composite drillpipe (CDP) is manufactured by winding carbon fibers over a mandrel while applying an epoxy matrix to encase the fibers and seal the assembly. CDP manufactured to date has had steel pin-and-box tool joints similar in design to conventional steel-drillpipe connections. The steel tool joints are attached to the composite tube during the winding process in which the carbon fibers are placed over specially designed ends of the tool-joint members to bond with the composite tube and resist fatigue in service. Currently produced CDP is approximately three times the cost of conventional steel drillpipe. As the technology improves and the capabilities of carbon-fiber manufacturers advance, this price differential may decrease.

CDP offers several potential advantages over conventional steel drillpipe that could make CDP particularly well suited to ERD and other critical drilling applications.
Deepwater-Riser-VIV Assessment Using Time-Domain Simulation
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 18769, "Deepwater-Riser- VIV Assessment Using a Time-Domain- Simulation Approach," by Kevin Huang, Hamn-Ching Chen, and Chia-Rong Chen, Texas A&M University, prepared for the 2007 Offshore Technology Conference, Houston, 30 April-3 May.

A computational-fluid-dynamics (CFD) approach was used to assess deepwater-riser vortex-induced vibration (VIV). The studied riser was a top-tensioned riser in 3,000-ft water depth. The proposed CFD approach is feasible for practical riser-VIV assessment. It also is an effective tool to disclose riser-VIV details, provide fundamental understanding and insight to VIV phenomena, predict riser VIV for complex current conditions, evaluate sensitivities including vessel motion coupling and transient effect, and verify riser-VIV design and analysis.

Introduction

Riser VIV is a design challenge for deepwater applications. Many software tools have been developed to perform riser-VIV analysis. However, most of the tools are based on empirical formulas and rely heavily on model-test data. This approach could provide satisfactory VIV predictions for shallow-water risers with a length/diameter (L/D) ratio that is relatively small, and model tests could be carried out easily to provide input data and/or verification. Deepwater risers are likely to have high-order-mode vibration in strong current. Under such conditions, model tests in a wave tank are difficult, limited either by tank size or model scale, and field experiments are feasible but costly. Further, important characteristics associated with deepwater-riser VIV are not yet studied or understood. Deepwater risers tend to experience multimode vibration; therefore, it would be overly conservative to assume single-mode lock-in. Also, the excited modes in deepwater-riser VIV could be very high; however, higher modes are more sensitive to damping and, hence, demonstrate strong nonlinear behavior.

The CFD approach uses an overset-grid technique to handle the data-grid movement caused by riser deflections and vibrations. A typical single-casing top-tensioned riser was sized for 3,000-ft water depth. The riser's dynamic response under different currents was simulated in 3D, and the effects of the riser/fluid interaction were included through instantaneous drag and lift forces. The riser in-line and crossflow responses (including modal shapes and frequencies) and VIV-induced stresses were studied in detail.
Overview: Well Testing (February 2008)
Authors: Stratton Jay
Published: February 2015

Overview

Well-testing papers under review for this feature become more numerous and varied each year. Consequently, this issue's papers represent a cross section of only some of the varied resource-development conditions under which industry professionals are designing and evaluating wells to determine productivity and reservoir parameters. The analysis of pressure data with accurate rate information is the root of petroleum engineering calculations.

Whether your need for measurement accuracy and resolution is a fraction of a psi for interference testing or hundreds of psi for qualitative depletion information on an infill-drilling project, knowledge of pressure is still fundamental.

The first paper describes the approach one operator is pursuing to refine their knowledge of one of the largest tight gas resources in the USA. Described are the constraints, challenges, and ultimate solutions they developed in pursuit of optimizing the recovery of this significant resource. The second paper provides a good example how integrating well-test design and analysis with existing geologic- and reservoir-description information enhances the accuracy of the final results. The third paper provides insight into the detailed planning and preparation that go into a successful well test and shares the post-job analysis comparing the actual test results with the original objectives. I am always amazed at the considerable planning and expense that go into oil/gas recommendations and operations that still lack any priority for capturing important (and relatively inexpensive) results for reference and optimization. This paper is a good read for anyone wanting an appreciation of the issues to be considered for well testing in challenging environments.

Many more good papers were reviewed than could be mentioned in this feature. The three selections listed for additional reading give us insight into the challenges faced and solutions implemented by service companies and operators to solve testing and interpretation needs in areas such as pressure testing while drilling, non-Darcy-flow modeling, and fracture properties of naturally fractured reservoirs.

The SPE eLibrary is a valuable resource that I encourage all to search for additional papers in your area of interest within the far-reaching topic of well testing.

Well Testing additional reading available at the SPE eLibrary: www.spe.org

SPE 103803 "Formation-Pressure Testing While Drilling in Bohai Bay's Challenging Environment" by Ulrich Hahne, SPE, Baker Hughes Inteq, et al.

SPE 107853 "Modeling Non-Darcy Flow and Perforation Convergence for Vertically Fractured Wells" by H. Huang, SPE, Georgia Institute of Technology, et al.

SPE 107418 "Effects of Stress on Fracture Properties of Naturally Fractured Reservoirs" by Abel Chacon, SPE, BP plc, et al.
Your SPE: Global Economic Crisis - Challenges for Industry and for SPE
Authors: Roodhart Leo
Published: February 2015

President's column

In my columns up to now, I have completely ignored the fact that the world is in an economic crisis at the moment. This is not because I travel around so much that I don't realize there is something going on. The simplest reason is that my column has to be completed more than 2 months before you read it because of publishing deadlines. The second reason is that SPE is a professional society that offers a forum for like-minded individuals in which an exchange of technical ideas and information can take place. In different words, we are not a lobbying organization and we do not do politics.

However, we are, as a society, part of the greater world and any crises, such as the current one, will affect SPE's operations. During the 50+ years of our existence, SPE has survived crises of all kinds, so I do not worry too much. SPE is financially very robust, with a good reserve fund built up during the last decade of growth and good support from members and organizations. However, everything SPE does is around oil and gas and that means that anything that affects oil prices will affect SPE.

So, what's going on? The oil market is inherently volatile; it has made a fool out of forecasters many times over the last decades, and it will make a fool out of me if I would even try to predict what will happen in 2009. On the one hand, we are made to believe that the current economic recession will end the growth in oil/energy use, which means that even if the supply growth slows, the extra production will not be needed and oil prices go down. Against that short-term view, there are a number of thinkers from our own industry, who I will cite here, who argue that our industry requires a long-term view. Analysis from sources such as Simmons & Company Intl., Douglas-Westwood, and the Paris-based energy think tank International Energy Agency (IEA) can be found on their web sites.

What they are saying is that, at the moment, many of the world's economies are still robust. The economies of India, China, and the Middle East are still growing, and China has a USD 1.9 trillion cash war chest. Of course, the financial crisis could spread into a serious economic downturn (and since this column is printed months after I write it, you will know), but oil demand should still grow in the longer term. In the short-term, new oil supply additions will get delayed because of the credit crisis. Mega energy projects may get delayed or cancelled, so supply will fall. But a recession will mean that demand for oil uses will decline, too. According to the Financial Times, the floor under the oil price is set by the level at which significant volumes of production become uneconomic, which the 21 December 2008 Financial Times says is around USD 30 to 40. However, if the industry slows down and production costs decline, that level will go even lower.
Modular Syncrude Conversion Drives Oilfield GTL Solution for Associated Gas
Authors: Hopper Chris
Published: February 2015

Technology Update

The associated gas that accompanies oil to the surface in a producing well can be a great advantage and valuable revenue stream, if your oil field is near a pipeline that feeds into a gas market. However, as oil fields move into deeper and more remote areas, away from population centers and gas infrastructure, the options for handling associated gas have become restricted and the question of what to do with it often difficult. The industry is crying out for a solution.

Historically, where there was no local market or available pipeline, associated gas was flared. However, this is now both environmentally and politically unacceptable, and in many countries banned. The alternative of gas reinjection is expensive and can cause reservoir damage, which adversely affects production and reserves.

Seeking a solution that avoids either of these alternatives, the industry for years has experimented with a variety of technologies.

For example, in areas with large associated gas volumes, the gas can be commingled into gathering systems and supply nearby specially constructed liquefied natural gas (LNG), methanol, or ammonia plants. However, this solution comes with a couple of major requirements.High gas volumes must be com-mitted in advance to justify the substantial plant-building cost.Commonly, supplementary nonassociated gas also must be available to offset supply fluctuations, including the eventual decline of field production. One example of how this supply-balancing requirement can work is the Bonny Island LNG plant in Nigeria, which ran on nonassociated gas until gathering systems were built that allowed associated gas to replace part of the original supply stream.

Without both of these prerequisites, commingling is not an option. With oil fields getting smaller and more remote, there will commonly not be sufficient reserves of associated gas to justify installing gas infrastructure or gas-processing plants. Even in areas such as the North Sea, where extensive gas infrastructure and a ready local market exist, small fields with short lives of 4 years or so cannot justify the expense of installing a gas export pipeline.

Other solutions proposed for dealing with associated gas that cannot be exported by pipeline have involved locating a gas-processing plant adjacent to the oil field and using technologies such as floating LNG, gas-to-liquids (GTL), methanol production, or gas-to-wire electrical power generation. These too tend to require large supplies of gas and considerable investment. For example, a standalone facility capable of consuming 100 to 150 MMscf/D of gas would have a capital expenditure of more than USD 1 billion. In addition, a facility would need a steady nondeclining gas stream, which often can only be achieved by combining associated gas with nonassociated gas from other fields. As such, this has led to these large facilities focusing on stranded gas with reserves of 0.5 Tcf or greater, rather than associated gas.
Industry Braces for an Uncertain Year
Authors: Donnelly John , Parshall Joel
Published: February 2015

Oil and gas companies are still adjusting to the sharp price volatility, collapse in credit markets, and global economic downturn of the past few months. But many analysts and forecasters believe that the medium- to long-term outlook for the oil industry has not changed, and that the need for more production, more people, and more research and development (R&D) remains.

Given the sharp swings in oil prices the past several months and the unknown depth of the economic recession, the outlook for the oil industry this year is anything but certain. The oil market is still digesting Organization of the Petroleum Exporting Countries’ (OPEC's) 4 million BOPD in production cuts since last September, the organization's steepest cuts in years. Even if OPEC member countries’ compliance with the cuts fall short, a considerable amount of supply will have been taken out of the market. Whether it is enough to make up for the erosion in global demand in the short term is unclear.

The price volatility of the past year has been unprecedented, with oil prices rising to USD 147/bbl before collapsing to under USD 40/bbl. Many OPEC members, including Saudi Arabia, have a target price this year of USD 75/bbl. Standard & Poor's and Moody's, largely watched investment ratings agencies, are currently using WTI price assumptions of USD 55/bbl and USD 50/bbl for this year, respectively.

Oil forecasters, including the International Energy Agency (IEA), the US Department of Energy's Energy Information Administration, and others predict sharp declines in oil demand this year. The consultancy Cambridge Energy Research Associates (CERA) forecasts a 660,000 BOPD decline in demand in 2009, following a 300,000 BOPD drop in 2008, the largest demand fall since the recession of the early 1980s.

The Long-Term View

But in its latest World Energy Outlook, the IEA believes the current economic storm has not changed the market's long-term outlook. It sees world energy use growing more slowly to 2030 than it projected last year, but still expanding by 45% between 2006 and 2030, with an average growth rate of 1.6% per year (Figs. 1 and 2). Fossil fuels will account for 80% of the globe's energy mix in 2030 with oil the dominant fuel. China and India will account for more than half of incremental energy demand to 2030, the IEA predicts, with the Middle East also becoming a key consumption center.