bluuebunny/crossref_metadata_2025_split huggingface dataset:
Gulf of Mexico Shelf Deep Ultra HPHT Completions - Current Technology Gaps
Authors: Hahn Dennis , Atkins Michael , Russell Jos , Pearson Bob 
Published: December 2007

Abstract
Numerous operating companies are pursuing new and much deeper geologic horizons on the Gulf of Mexico continental shelf. This is a logical expansion of a geographic area with a very mature and well established surface infrastructure. However, as the well depths increase, the wellbore construction and well production operations become much more challenging because ultra-high pressures and high temperatures - HPHT (e.g. 25,000+psi and 450+°F) will then need to be handled and/or managed. The industry is probably able to safely drill these more extreme wells but there are some significant well completion technology gaps that require design and development. The most cost efficient approach to bridge these gaps may be for several companies to collaboratively share in the costs to develop the appropriate equipment for these applications.
This paper demonstrates the need to enhance the industry's capability to actually begin production from these deep ultra HPHT wellbores. The numerous areas that require increased completion capability will be presented in this paper. The production tubulars (casing and tubing) will be a major cost driver as designs will need to address temperature deration of strength, geometric complexity to achieve adequate bore and clearances, corrosion and environmental cracking. Risk analyses and testing will dictate metallurgy, pressure containment, connection capability under compression and bending, and benefits and reliability of cementing. Production packers, subsurface safety valves, and flow control nipples/plugs appear to be the nearest to implementation, but some design and qualification issues still need to be resolved. Current perforating technologies are reaching their limits at temperatures exceeding 450°F, thus require significant attention in their specific application and a quality assurance/quality control (QA/QC) program. The major hurtle for fully rated completion blowout preventors (BOP's) and trees will be the need to redesign the valve stem sealing mechanisms. Finally, both intervention and contingency possibilities, like slickline, pumping services, stimulation, snubbing, etc., are important situations that require additional enhancements to currently available technologies.
Design and Qualification Challenges for Mudline Well Control Equipment Intended for HPHT Service
Authors: Berckenhoff Mike , Wendt David 
Published: December 2007

Abstract
In recent years there has been an increasing interest in the development of high pressure/high temperature (HPHT) prospects, requiring enhanced equipment designs for operation in this environment. The more severe HPHT wellbore conditions, often defined as any reservoir pressure exceeding 10,000 psi and temperature above 300°F1, necessitate changes in design criteria and operational procedures. The resulting requirements may range from simple upgrades of existing designs to complete redesigns with new materials and geometries. This paper will discuss some of the additional types of analysis and testing required to qualify mudline well control equipment for these more severe conditions. Additionally, changes to operating procedures for this type of equipment will be presented.
Stochastic Kick Load Modeling
Authors: Mason Stan , Chandrasekhar Sharat 
Published: December 2007

Abstract
As our industry starts to plan and drill ultra-deep wells, we are beginning to find that the established methods for calculating maximum anticipated surface pressure (MCP) produce loads that exceed the strength of many conventional API weights and grades. Addressing this situation, regulators have entertained modifications to the methods by which we calculate MCP. Although this is becoming a common practice, the approach is flawed in that it is arbitrary in nature and only partially considers the real-world limits placed on our drilling system. Furthermore, no method used to date addresses the fluid miscibility issues that we encounter with the oil-based muds used to drill these wells.
A stochastic kick load model specifically developed to consider the entire physical system in which a kick is initiated and dealt with, offers a higher level of confidence than any arbitrary method can. After a review of two commonly used MCP calculation methods, this paper will describe, in detail, one such model, the inputs required, the assumptions used and the outputs generated. This paper concludes with a discussion of the challenges facing those who wish to implement such an approach.
The Qualification of C110-High Strength Sour Service Casing–A Statistical Approach to Evaluating Material Data Across A Single Production Heat Lot
Authors: Urband Bruce E. , Garrison Brian , Prideco Grant , Cernocky Paul , Tallin Andy , Sponseller David L. 
Published: December 2007

Abstract
Designing casing for ultra-high pressure, high temperature (HPHT), hydrogen sulfide bearing wells creates a need to characterize the sour performance uncertainty (scatter) of higher strength, low alloy carbon steels casing such as grade C110. Casing properties generally vary by: source mill, degree of hot working, product type (seamless pipe vs. electric resistance welded pipe), steel chemistry, size and wall thickness, particular heat lot, particular joint of pipe, and location on the joint of pipe. Measured properties also can vary according to the number of and choice of laboratories doing the testing. All of these factors can contribute to the perceived scatter in the sour material properties associated with the product. In order to determine the mean and scatter of sour properties which characterize grade C110 casing and create a benchmark for the minimum possible scatter that can be achieved in a production order at a level practical for well design, Shell International E&P and Grant Prideco-TCA jointly generated a population of sour property test data across a single, commercially produced, heat lot of casing and using the services of a single NACE testing laboratory, OMNI Metals Laboratory. Grade C110 is a high strength sour service material, which is currently being considered for standardization by the American Petroleum Institute (API).
This paper details the results of sixty-six NACE Method D (DCB) tests and seven NACE Method A (tensile) tests conducted across one single, commercial production heat lot of Grant Prideco-TCA grade C110 low alloy carbon steel. All tests were conducted at OMNI Metals Laboratory. The data conceptually represent the tightest possible practical spread of sour material properties since all the data were obtained from a single heat lot of pipe sampled every 10th pipe-end and along a joint of pipe within the single lot. Hardness was found to be remarkably uniform. Results of the data are correlated in terms of model uncertainty for KISSC vs. hardness. The paper also presents a correlation between hardness measured on pipe-ends and hardness measured on the corresponding NACE specimens. Tests were performed in standard NACE A Solution and at milder conditions. For this grade material, the mean DCB results were significantly higher than the industry trend and the scatter was unusually low indicating high product consistency across the heat. Results quantify the impact of reducing the H2S concentration to a fit-for-purpose environment based on NACE Method D test data.
Metallurgical Limits to Increasing Tubular Strength While Maintaining SSC Resistance
Authors: Craig Bruce 
Published: December 2007

Abstract
There is a demand in the petroleum industry for high strength casing and tubing steels that have yield strengths exceeding 110,000 psi and yet have acceptable resistance to sulfide stress cracking (SSC). However, contrary to expectations and the desire to simply enhance current steel compositions and processing, there are no easy means to achieve increased strength and maintain or increase the SSC resistance at the same time. Only small incremental increases in performance can be achieved with current conventional tubular manufacturing and the limit of these increases has been reached. This paper will present the factors that increase the SSC resistance of conventional high strength steel tubulars and their limits which have been exhausted at this time. Possible ways forward to meet the challenge of high strength tubulars with good SSC resistance for HPHT wells will be discussed.
Premium Connection Design, Testing, and Installation for HPHT Sour Wells
Authors: Bradley A. B. , Nagasaku S. , Verger E. 
Published: December 2007

Abstract
Drilling and completing wells deeper, and in HPHT sour environments, magnifies the importance of having reliable threaded casing and tubing connections. High pressure/high temperature wells present many critical challenges for threaded tubular connections. Through design, proof testing, and installation, premium connections are meeting these requirements in a number of ways. With coupling stock for thick walled tubulars and sour service environments often being the limiting factor as the pipe wall increases, integral connections, and threaded and coupled designs with pin to pin contact allow the use of production casing over one inch in wall thickness. The incorporation of resilient seals into threaded and coupled connections can offer secondary back-up seals to the primary metal to metal seals.
Premium connection designs are often required to be validated or pass a qualification test program before acceptance by the users. Two fundamental approaches exist for qualification testing; product line testing and project specific testing. Product line testing is used to "qualify" a range of dimensions and wall thickness within a given design and is often accompanied by Finite Element Analysis (FEA). Project specific testing is used for very critical applications and when the connection designs are tailored to meet specific requirements. The ISO 136791 test procedure is most commonly used as the basis for qualification testing although "modified" ISO and other qualification test procedures are also used.
The design and qualification of HPHT connections determine that the connections are fit for purpose and that they provide reliability for HPHT well applications. The installation process is also a critical issue in the successful drilling and completion of such wells. Computer controlled make-ups, low stress or non-marking dies in handling equipment and even the application of the proper thread compound and quantity can be critical components in the successful completion of HPHT sour wells.
The Effect of Radial Loads on Connection Design in Ultra High Pressure Wells
Authors: Gonzalez Manuel E. , Wu Jiang , Hensley J. Rodney , Chandler R. Brett , Muradov Andrei , Jellison Michael J. 
Published: December 2007

Abstract
The industry has been designing casing and tubing for wells for many years by using the expected operational loads to calculate the triaxial stresses on the tubular walls. Part of the triaxial stresses is the radial component. In most cases pressures less than 15,000 psi, the radial triaxial component is not a major factor in the stress on the tubing wall. However, on higher pressure wells (above 15,000 psi) this radial component becomes significant in the design of the tubing and casing. During the conceptual design of ChevronTexaco's deepwater Tahiti project, several wells were projected to depths of anywhere from 26,000' to over 30,000' TVD. Under certain operational loads (such as fracturing or perforating), the pressures at the deeper horizons can exceed more than 25,000 psi (both inside and outside the tubing). We then asked ourselves a question, "If the radial load becomes significant on the actual tubing wall, what would the same radial load do to our connections"? It is very important to point out that you can have no differential pressure across a connection and still have intense radial loads.
Corrosion and Environmental Cracking Evaluation of High Density Brines for Use in HPHT Fields
Authors: Piccolo Eugenio Lo , Scoppio Lucrezia , Nice Perry Ian 
Published: December 2007

Abstract
In high pressure high temperature (HPHT) gas condensate wells the use of high density brines is required to ensure safe well operations during both well drilling and completion phases.
This investigation studied the corrosion and environmental cracking behaviour of several high density brines in simulated HPHT conditions.
The tested materials were low alloy steel grades P-110 and C-110, supermartensitic stainless steel (S13Cr) grade 110 ksi, duplex stainless steel, galvanized carbon steel wireline, duplex stainless steel wireline, superaustenitic stainless steel (N08535) and alloy 718. These materials were tested as single corrosion coupons, c-rings and four point bent beam specimens.
A test program was embarked, selecting experimental conditions representative of future HPHT Field developments in the Norwegian Continental Shelf.
The test results showed that S13Cr and duplex stainless steel suffered SCC failure in CaCl2 and CaCl2+CaBr2 brines at HPHT.
The effect of corrosion inhibitor with these brines was variable, but acceptable to low alloy steels.
It was also found that alloy 718 suffered a significant loss in ductility due to hydrogen embrittlement when exposed to caesium formate. But this did not result in cracking failures under the static loaded test conditions.
S13Cr suffered both general and superficial pitting corrosion with evidence of initiation of SCC associated with the pits when exposed to caesium formate.
Updated Design Methods for HPHT Equipment
Authors: Young Kenneth , Alexander Chris , Biel Richard , Shanks Earl 
Published: December 2007

Abstract
Drilling industry technology is advancing rapidly. Drillers are encountering downhole pressures over 20,000 psi and temperatures over 450°F. These high pressure high temperature (HPHT) conditions require drilling and completion equipment that is beyond the scope of today's API specifications.
API specifications 6A1, 16A2, 16C3, and 17D4 address the design and design verification methods for drilling equipment. These specifications currently reference the ASME Boiler and Pressure Vessel Code, Section VIII, Division 25 (ASME VIII-2) as one of the primary design verification methodologies. API specifications first referenced ASME VIII-2 as a design verification methodology nearly 20 years ago, because it was the best available at that time. This is called the " ASME Method".
The ASME Section VIII, Division 36 (ASME VIII-3) was developed to give the requirements for the construction of high pressure vessels. ASME VIII-3 was first issued in 1997 and is intended to be used in place of ASME VIII-2 for high pressure vessels, generally in excess of 10,000 psi.
The design of drilling and completion equipment should be done using first principles. The authors propose that the designs for 15,000 psi or higher service should be verified using the rules from ASME VIII-3. A significant difference between the two design verification methods is that the user specifies the loading criteria for the performance-based ASME VIII-3. ASME VIII-3 requires cyclic load (fatigue or fracture mechanics) analysis and has limitations in materials, fabrication and inspections, and testing requirements that specifically apply to thick-walled pressure vessels.
This paper discusses how the performance-based code methods of ASME VIII-3 can be integrated into API specifications for HPHT drilling and completion equipment.
Completion Optimization: Equipment & Material Qualification
Authors: Harris David , McGee Kerr , Frick John , Lane Bryan , Schwind Brian 
Published: December 2007

Background
Engineering of completions programs that are reliable and cost effective is a fundamental responsibility of the drilling and completion community. Reliability methods for HPHT and critical well design are the most effective means of controlling schedule, cost, performance, and risk, which combine to define Life Cycle Cost (please refer to Figure 1). Optimization requires mechanical integrity while maximizing flow capacity of the system, thereby eliminating lost production and workover costs. Deep well costs can be among the greatest of the industry.
Reliability methods are common in industry and have seen increasing application in Exploration and Production. Reliability methods are not merely concerned with quantifying risk-rather the ultimate goal is production optimization with a robust system. System analysis, operating environment evaluation, component assessment, and data management are required in a reliability program and in optimized stochastic modeling. Following a discussion regarding production system design optimization the topics of material and equipment qualification will be presented. Drilling and completion optimization involves qualification of design (often through variability assessments and worst case analysis), Manufacturing (typically suppliers, material, and component qualification), assembly (which may include FAT1 and qualified rig procedures), and operations (that is operating within design limits).
Production system optimization addresses the four principal sources of failure shown in Figure 2. An integrated team is initially applied to optimize the completion program considering these four viewpoints, and then the team efficiently and cost-effectively executes the plan with specialists. Net present value of risked production and cost are used in optimization.
Gas Injection Feasibility Study of the Baram Delta Fields, Malaysia
Authors: Zain A. N. M. , Sudirman S. , Valdez R , Doe P. H. , Ray F. , Chai C. F. 
Published: December 2007

Abstract
A joint gas injection feasibility study by Shell International E&P Inc., PETRONAS and PETRONAS Carigali Sdn. Bhd. has been conducted for the Baram Delta Operation (BDO) fields, offshore Sarawak, Malaysia. The goal of the study was to design a robust pilot project to evaluate and prove the commercial viability of basin wide gas injection. The study consists of several phases, the first of which, and the focus of this paper, is to conduct a screening study to estimate EOR potential and select a gas injection pilot location. The total EOR potential from initial screening was estimated at 200+ MMSTB from six of the nine BDO fields. Building prototype static and dynamic models of the top five ranking EOR targets further refined these opportunities.
To enable screening and ranking of these targets, a spreadsheet based tool was constructed, which allows for rapid re-screening of reservoirs based on starting assumptions. The tool developed, BDO EOR Screening Tool (BEST), is based on several subsurface and surface criteria. The design of the tool allowed for screening of the total EOR potential and to determine the optimal pilot location. The screening required both immiscible and miscible gas injection potential to be estimated.
The top five candidates, based primarily on EOR potential, were modeled and the potential verified using reservoir simulation. The fully miscible injection cases, Baram field as an example, showed similar results to screening estimates; however, the near miscible and immiscible cases at West Lutong and Tukau fields respectively showed a lower potential. Ultimately, the West Lutong M/N reservoir was chosen as the gas flood pilot location for the following reasons: (1) large EOR potential in the M/N and K/L reservoirs, (2) minimum miscibility pressure (MMP) is at or near current reservoir pressure, (3) depositional environment analogous to several other reservoirs in BDO, and (4) considered one of three large targets required to implement large scale gas flooding in BDO.
This paper presents the methodology used in the screening of 1,000+ reservoirs and the unique features employed to develop representative prototype models using analogue field data.
Integration of New Open Hole Zonal Isolation Technology Contributes to Improved Reserve Recovery and Revision in Industry Best Practices
Authors: Henriksen K. H. , Augustine J. , Wood E. 
Published: December 2007

Abstract
This paper discusses developments in horizontal well completion practices. During recent years, the pursuit of screen based open hole completions with zonal isolation in deviated and horizontal wells has fostered the development of new technology, new applications, and processes to improve recovery of oil and gas. Based on case histories, computer simulations and laboratory testing, this paper describes recent findings which have lead to revisions in completion design and operating best practices.
Microscopic Rock Characterization and Influence of Slug Size on Oil Recovery by CO2 Miscible Flooding in Carbonate Oil Reservoir
Authors: Shedid S. A. , Almehaideb R. A. , Zekri A. Y. 
Published: December 2007

AbstractCarbon Dioxide (CO2) has been recognized as a preferred miscible solvent for Enhanced Oil Recovery (EOR) methods. Miscible flooding by CO2 has proven its positive effectiveness through numerous laboratory and field projects. The main goals of this study are to provide microscopic reservoir rock characterization, and optimize the selection and the effect of CO2 slug size to be applied for carbonate oil field, U. A. E., on oil recovery by CO2 miscible flooding.Scanning Electron Microscope (SEM) is used to provide accurate description of the reservoir rock surface topography. The SEM is used to attain the pore size distribution of the rock. Energy Dispersive X-Ray Spectrometer (EDS) and Inductively Coupled Plasma (ICP) are applied for detailed accurate analysis of elements constituting the rock.Five flood experiments were performed to achieve the goals of this study. The first experiment was carried out using continuous CO2 flooding. Other three experiments used different CO2 slug sizes of 0.15, 0.30, and 0.45 hydrocarbon pore volume and chased by actual reservoir brine. The fourth experiment was carried out to evaluate the performance of waterflooding. All experiments were performed using actual crude oil injected into actual reservoir rock samples of almost 23 cm length and 10 cm diameter. These samples were saturated at initial-oil-in-place condition and then subjected to water and/or CO2 floodings. The minimum miscibility pressure (MMP) was calculated to be 3,700 psia using current correlations from literature. To secure good miscibility condition, all experiments were conducted under injection pressure of 4,200 psia and at 250 °F similar to the reservoir condition.The results indicated that water flooding recovered 66 % IOIP and a continuous CO2 miscible flood produced 96 % IOIP. Furthermore, the increase of slug size increases oil recovery by CO2 miscible flooding, but the slug size of 0.15 HCPV is recommended since the increment in oil recovery using larger slugs does not represent significant addition to the oil recovery in comparison to applied smaller slug sizes.