bluuebunny/crossref_metadata_2025_split huggingface dataset:
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.