bluuebunny/crossref_metadata_2025_split huggingface dataset:
Integrated Approach to Deep Water North Sea Drilling
Authors: Wilson G.J. 
Published: October 2008

ABSTRACT
Ever increasing costs associated with drilling operations in a hostile marine environment dictate that the ratio of actual drilling time to total time expended be increased to the greatest possible limit consistent with safety. This paper discusses equipment, materials, procedures, and personnel required to fully utilize capabilities of new generation semisubmersible rigs in achieving this goal during year-round drilling operations in deeper water in adverse environments. Criteria established for selecting basic equipment and innovative items are outlined. Procedures and auxiliary components needed to assure compatibility of subsystems and the effect of new concepts on primary drilling objectives are reviewed. Responses to the problems of resupply and support, measures conceived to promote timely and advantageous use of specific skills of all personnel and benefits resulting from shallow marine studies are presented.

INTRODUCTION
High cost of deep water drilling in a hostile environment demands the greatest possible effectiveness of all equipment and personnel. Daily costs for operating and supporting one of the new semisubmersible rigs total about $50,000. Costs are not expected to decline and will no doubt exhibit further increases as deeper water in the more open reaches of the sea is challenged. Employing inadequate equipment with an apparent savings in daily rental cost has long been recognized as false economy. The operator therefore has little recourse other than to accept greater costs. But conditions in higher latitudes of the North Sea, in the Gulf of Alaska, off Canada and in other offshore areas around the world are such that the best drilling rigs and supporting units will continue to be subjected to long periods of rough weather during which little, if any, productive work can be performed. Since all costs are ultimately borne by the operator, the operator has a great incentive to accomplish more productive work in less time than here to fore but without incurring greater per well costs.
Two complementary approaches can be made to obtaining more productive work which, from the operator's viewpoint, can be defined as the actions directly connected with drilling hole and evaluating horizons penetrated by the bit. First, the ratio of time spent in productive work to total rig time can be increased to the greatest limit consistent with safety. Second, the most optimum procedures can be formulated and implemented for all phases of the operation. The first approach requires investment in equipment to supplement the minimum with which the drilling goal could be reached if total time and total costs were of little importance. Even though most drilling contractors provide somewhat more than minimum equipment, in the context of this paper, basic equipment in the context of this paper, basic equipment refers to the minimum.
Marine CNG: Technically Sound, Commercially Viable, and Imminent
Authors: Young C. , Eng P. 
Published: October 2008

Abstract
One of the newest frontiers in the upstream energy sector is marine compressed natural gas (CNG), and the economic challenge of how to safely transport and market marine CNG on a regional or international basis. Stakeholders are working to meet these challenges head-on and are creating solutions for all aspects of development, transportation and delivery of a reliable CNG product to varied customers.
Traditional concerns surrounding technical feasibility have given way to economic considerations on a project by project basis, with increased focus on the niche capabilities that marine CNG fulfills. Proponents have succeeded in overcoming the technical challenges and have attained regulatory approvals for their designs and are in a race to be the first successful application of this technology.
The Centre For Marine CNG Inc. has been tracking the progress of all the proponents, while advocating for the technology as a whole. While research continues on the technical aspects of CNG, the gas owner/operators have recognized that the first project is imminent and are following the technology appropriately.
This paper serves to provide an industry update, describing the niche that CNG fills in comparison to LNG or other natural gas monetization strategies, identification of thetechnology proponents and the relevant regulatory approvals, as well as some basic economic models to help validate the viability of marine CNG.

Introduction
From the Oil & Gas industry perspective, one of the obstacles to a stranded gas development is that marine CNG, as a monetization strategy, is not yet in commercial operation anywhere in the world. Many owners worldwide have struggled with how to monetize their gas reserves when the conventional options of a pipeline or LNG development do not fit the characteristics of their reseroirs.
In general terms, marine CNG differs from LNG in that the natural gas is compressed, rather than liquefied for transport. Depending on the proponent, the gas is transported in a range of 1500 to 4000 psi to achieve energy densities of approximately 1/3 of their liquefied counterpart of LNG. The gas is stored in pressure vessels aboard a CNG ship that will then transport the gas to market. Depending on distance to market and the demands for non-interruptiple supply, multiple ships would be required to maintain "flow". One could consider the CNG solution comparable to a floating pipeline, with much less infrastructure required for exploitation of the natural gas reserve. Loading and unloading requirements are comparable to and adaptable from both LNG and oil transfer systems, while the transport vessel can range from a small volume barge to a large capacity LNG-sized vessel.
Given the capability of marine CNG transport as amonetization strategy, one must ask why this method has not yet been implemented. The first and most obvious answer is the hesitation of any owner to be the first to employ a new and unproven technology on a large scale development project.
A New Offshore Platform and Drilling Concept for Reduced Costs
Authors: Sybert Jack H. 
Published: October 2008

ABSTRACT
A new concept has been developed and used to reduce cost of offshore oil and gas drilling platforms. Six dually completed wells were drilled from a platform in the Gulf of Mexico, using two 48-in. diameter piling as guidesthree in each pile on a spacing of 23 in. The conventional conductor guides in the platform were eliminated, reducing the design wave load, the steel required and the cost. New drilling equipment, techniques, and wellhead equipment were developed and are described. Cost comparisons are presented. Plans for expansion of the concept to a 12-well structure are described.

INTRODUCTION
Offshore platforms represent some of the world's most expensive real estate. Designers are continually trying to reduce this cost, but face higher costs with increasing water depths, material and labor costs, and regulatory action. A new concept for a platform and drilling operation has been developed, and significant saving may be realized from its use.
The cost reduction is achieved by drilling through the legs of the platform. In itself, this concept is not new because if has been used in platforms in Cook Inlet and off the U. S. west coast. In those platforms, large- diameter columns (diameters approximately 16 ft) contained wells drilled on spacings as close as 5 ft on centers. These wells were drilled through individual guides driven or drilled to the desired depth below the mudline. The new concept presented here is the close spacing of the wells and the absence of the individual guides for each well.

TYPICAL MULTIWELL PLATFORMS
Multiwell platforms usually have six or more pilings for support. A typical configuration for a 12-well, eight-pile platform is shown in Fig. 1. The deck section is normally trussed and provides two levels for producing and drilling operations. The wells are located in the inside bay and are drilled through 24-in.-diameter conductor pipes that are driven into the bottom and supported by the platform.

MAIN PASS 133-A PLATFORM
The Main Pass 133-A platform is located 48 miles east northeast of Venice, La., in the Gulf of Mexico. The water depth is 180 ft. It is a four-pile platform (Fig. 2) that has seven dually-completed wells. The jacket was placed over one well that was an on-bottom, suspended well drilled from a mobile drill barge. The remaining six wells were drilled from the platform.
The deck section was built with a grid of 12-ft high plate girders that are framed intercoastally. Nominal dimensions are 117 × 75 ft. The area around each well cluster is covered with floor plate, but the remainder is left without permanent decking during the drilling phase. Temporary walkways provide the needed accesses. The advantage of this arrangement is the opportunity to fabricate production facilities into units that provide decking and can be placed on the structure after drilling operations are completed.
First Jack-Up Production Platform In North Sea
Authors: Cheng Alymer P. , Keleher Jerry F. 
Published: October 2008

ABSTRACT
This paper describes the platform design engineering aspects of Amoco's jack-up gas production platform which was installed in August, 1972. It is the first jack-up production platform installed in the North Sea.
The main advantage of using the jack-up platform as compared with the conventional template-type platform is that all production, storage, and living facilities can be installed, tested, and checked out in the fabrication yard prior to leaving for installation. As a result, considerable expensive offshore work is avoided, and more important, much less time is required to commission the production facilities and begin operation.

INTRODUCTION
The Oil Industry is constantly searching for new methods and systems to reduce the high cost of offshore installations. Particular interest is being shown in producing facilities required to be located offshore. These installations can vary in size from a single separator to a bulky, highly instrumented gas dehydration complex. The first step toward economy was the "skid mounted" unit which combined a principal unit with pumps, meters and instrumentation installed and possibly tested on a set of skids designed for lifting into place on the offshore platform. Later the deck sections were sectionalized. The equipment was installed integrally with the deck section pieces and then finally assembled and tested offshore. Still later the idea of "production packages" (more commonly referred to now as modules) came into use. For the larger facilities and deep water locations this method appears to be the most popular at the present time. To date, this arrangement appears to be planned for all deep water North Sea installations. For this type operation the equipment is installed in a series of structural steel boxes. The boxes are fabricated in the yard in the exact position they will occupy in their final location offshore to insure a final, correct inter-connection. The entire system can then be tested as a unit in the yard. Once installed offshore only a minimum amount of final testing is required.
One type of permanent installation that has seen limited use is the "jack-up" barge. Some use has been made in the Gulf of Mexico, but principally for storage. One such installation for large separator units is known by the writers to be in use in the Middle East.
Amoco, having used the three previous mentioned methods in the British North Sea, investigated the use of a jack-up barge, in an effort to further reduce offshore connection work and testing. The results of the investigation showed this method feasible and economical up to approximately 100 ft. water depth. The decision was made to use the "jack-up" barge concept on a gas dehydration facility to be installed in a 75 ft. water depth location in the Leman Field, British North Sea.
Installation Challenges With Lifting and Pull-in of the 20" SCR
Authors: Bouwman John 
Published: October 2008

Abstract
During the 1st half of 2007, Heerema Marine Contractors will install the 20 inch Export SCR to the Independence Hub Facility, using Deepwater Construction Vessel Balder (figure 1).
This 20 inch Export gas pipeline will be the deepest export pipeline installed to date and will be installed as part of the installation program of the Independence Hub Facility and SCRs.
The offshore installation of the 20 inch Export SCR requires utilization of equipment to its maximum. Technical challenges involved are among others the pick-up of the SCR that has been pre-laid on top of four SCRs (2x8-inch, 2x10-inch), transfer of SCR from A&R Winch System to the Balder crane and reduction of loads on the SCR head during pull-in. This paper describes the most important issues of this SCR installation project, including methodologies specifically developed to deal with the technical challenges of this project.

Introduction
On July 15th 2004, Enterprise Field Services, LLC awarded the contract for the installation of the floating production facility, Independence Hub, to Heerema Marine Contractors Nederland B.V (HMC). The Independence Hub Facility (IHUB) will be installed in Mississippi Canyon Block 920, in 8,000 ft of waterdepth.
The Independence Trail Pipeline is the Export Gas Pipeline for the Independence Hub Facility. This pipeline system will initiate with the 20 inch diameter Export Steel Catenary Riser (SCR) on the IHUB.
Part of HMC's scope is the installation of eight SCRs to the IHUB. Five 8 inch SCRs, two 10 inch SCRs and the 20 inch Export SCR. All pipelines, including SCRs have been constructed and temporarily stored, pre-laid, on the seabed (figure 2). Each SCR consists of steel pipe with an integrated flexjoint and a SCR head on the pipe end. Pre-installed on the SCRs are strakes and fairings to avoid vortex induced vibrations, a flex joint protective cover, flex tool, pipe flooding valves, hang-off collar and a pick-up rigging arrangement including buoy for installation purposes. After installation of the IHUB, the SCRs will be recovered and connected to the IHUB.
The SCR installation will be done by HMC's Deepwater Construction Vessel (DCV) Balder. DCV Balder was built as Semi-Submersible Crane Vessel in 1978 and underwent an extensive life time extension and conversion program in 2001. [Ref 1] DCV Balder is specialized in installing complex deepwater field architecture and is well suited for the installation of the 20 inch Export SCR.
Some characteristics of Balder equipment used for the SCR installation are:DP Class III, with a thrust capability of 350 mTDual crane capability, with deepwater capacity of 250 mT at 3000 m waterdepth.Mooring Line Deployment Winch (MLDW), with a capacity of 310 mT. (Static wire load including 12% dynamics) [ref 1]Abandonment and Recovery Winch System (A&R), with a hoisting capacity of 650 mT. [ref 2].
For the installation of a single pre-laid SCR to the IHUB, the following phases have been distinguished:
Innovative Pipe System for Offshore LNG Transfer
Authors: Frohne Christian , Harten Friedrich , Schippl Klaus , Steen Knut Erik , Haakonsen Rune , Eide Jorgen , Høvik Jon 
Published: October 2008

Abstract
For more than 30 years LNG ship to ship loading has been addressed by several Gas operators. One of the main technical challenges that have been identified has been how to extend and combine the proven technologies of static small bore diameter cryogenic piping and offshore ship to ship transfer of oil to large diameter offshore LNG transfer.
In the last years the market has pushed for flexible piping suitable for LNG offshore loading systems, and the industry has responded with different technical solutions based on very different design criteria. In this paper the basic requirements for a
LNG offshore loading system are presented. As a minimum the requirement of the European code prEN 1474 - II is quoted.

Design Classification of LNG Flexible Pipes
Today there are two completely different flexible pipes designs existing on the market, both are proven in their applicationsComposite hosesFlexible metal pipes based on corrugated stainless steel pipes (sometimes called " bellows?? although not necessarily based on the bellows technology, which is in principle limited in length)
The composite hose is a proven technology for a wide range of applications, amongst others the offshore loading of all kind of ambient temperature liquids. In the LNG business they are available as emergency unloading hoses.
The flexible metal pipe has been used in smaller diameters for more than 30 years for all kind of cryogenic applications, transfer lines for Liquid Nitrogen, Helium and even Hydrogen and Oxygen.
So for both design options, the LNG ship to ship loading is a new application of a well known technology
An Evaluation of Perforating Techniques and Use of Caesium Formate Kill Pills to Optimise Productivity in HPHT Gas Wells and Minimise HSE Risks
Authors: Roy Alistair Malcolm , Twynam Allan Jeffery , Parke Jeff , Morrison Angus , Downs John 
Published: October 2008

Abstract
The BP Operated Rhum Field is a North Sea High Pressure High Temperature lean gas field. A key design requirement for successful development well planning and execution was to evaluate Overbalance and Dynamic Underbalance perforating techniques for their potential to optimise productivity while reducing the risk of producing hydrocarbons to surface during downhole operations.
In this paper we present a case history focussing on the evaluation of the available perforation techniques with the aim of matching or exceeding the flow performance achieved on the Appraisal Well DST. The selection of drill pipe conveyed dynamic underbalance perforation, using the Schlumberger PURE technique provided the best compromise in terms of minimising HSE exposure and maximising productivity, with the main potential downside being the potential for large cost over-runs from utilising Caesium Formate brine. The re-completion of a Rhum appraisal well provided a rare opportunity to obtain a direct comparison of well productivity from standard Underbalanced and Dynamic Underbalanced perforating operations in the same reservoir interval.
Operational issues forced the Rhum team to utilise a third perforation technique, on-balance perforation via electric line, and the paper will present the productivity achieved using this technique also.
The paper progresses sequentially through the following items;An overview of the Rhum Field and Reservoir;Design and Planning of the perforation techniques utilised on Rhum Development wells to overcome challenges such as Hard Rock Perforating and Sand Control requirements;The detailed design and core flood testing of two different types of Caesium Formate Kill Pills, aimed at identifying the least-damaging formulation.
Operational data is presented to demonstrate the success of dynamic underbalance in maintaining a full fluid column, effective gas suppression in clear brine and tight fluid loss control. Field production and pressure data showing the filter cake clean-up over time is examined to evaluate the actual performance of the chosen kill pill after extended exposure at downhole temperature.
The paper concludes with a comparison of the flow performance achieved on a single well in an identical reservoir interval when shot with ;standard underbalance during the original appraisal DST operation anddynamic underbalance for the development completion operation (original perforations cemented off).
These results are compared with the flow performance of a second well shot on-balance using electric line.
Mitigation of Ice Risk to Subsea Infrastructure
Authors: Morgan Vincent , Phillips Ryan Douglas , Randell Charles , Freeman Ralph 
Published: October 2008

Abstract
A review of the current capability within the industry is given for assessing the iceberg environment and iceberg keel / seabed structure interaction, with emphasis on operations relevant to the east coast of Canada. Consideration of calculating contact frequency and ice loads for iceberg keel impact is discussed, for both freely floating and gouging icebergs. Available environmental data for the Labrador Shelf and Grand Banks of Newfoundland are summarized. An overview of the operational experience of placing subsea production facilities in glory holes to provide protection from iceberg keels is provided, along with a review of studies related to the development of alternative solutions. Studies have been performed to investigate the feasibility of design and construction of cased (or silo) glory holes, external protection structures such as rock berms and steel or concrete structures, and the effects of direct impact scenarios such as the use of caisson wellhead systems.
Ongoing efforts to improve the knowledge base, analytical capability and engineering solutions to predict the effect of iceberg keel loading on subsea oil and gas facilities are described. Obstacles to safe and economic development are identified, along with a discussion of methods that can be used to overcome these and provide practical solutions for future development.

Background
Over 25% of the world's petroleum reserves are believed to be in arctic regions and other offshore, ice frequented environments. As world energy demand increases, development of oil and gas resources in harsh ice environments is being increasingly considered by industry. The advancement of safe, cost-effective and reliable engineering solutions for subsea infrastructure in ice environments is a key requirement for sanctioning stand alone and marginal field developments. Subsea infrastructure requiring protection from ice keel contact includes components such as wellheads, production trees, manifolds, umbilicals, flowlines and pipelines.
This paper describes an ongoing joint industry project that was initiated to address uncertainties and develop approaches to mitigate the risks associated with oil and gas development in ice-prone regions. The project comprises two components that address differences in approach for issues related to pipelines in Arctic regions, and subsea production facilities in sub-Arctic regions. It is funded by a combination of the Atlantic Canada Opportunities Agency through its Atlantic Innovation Fund and a number of large oil and gas operators. Project collaborators include private companies, government agencies and academic organizations.