bluuebunny/crossref_metadata_2025_split huggingface dataset:
Recent Developments in Deep Sea Electrical Resistivity Probings - Its Application to The Sedimentary Study of the Red Sea Hot Brines
Authors: Kermabon Andre J. 
Published: October 2008

INTRODUCTION
Previous studies have been made of the mass physical properties and the electrical resistivity of marine sediments. A third degree polynomial curve was found to, be the best fit for data relating porosity and the formation factor, which is the ratio of the bulk resistivity of marine sediments to the resistivity of interstitial water. An electrical resistivity probe has already been successfully used to obtain in-situ profiles of resistivity vs depth.
A new instrument is now described where a similar principle is used for the study of the lithology of the Red Sea hot brines. In order to increase the definition of the measurements, the new probe is provided with a focused resistivity measuring device, that is less affected by borehole effects. This new probe is devised to operate in an environmental temperature of 700C and a salinity of 35 percent of salt content in water as well as in the interstitial water of the sediments.

PREVIOUS DEVELOPMENTS IN THIS FIELD

General
Archie,1 Rust (1952), Atkins2 and Kermabon4 successful correlated some physical parameters of reservoir rocks in sedimentary strata with their electrical resistivity. The sandstones investigated had porosities ranging from 10 to 40 percent and were saturated with brine of known salinity. The following simple relation was defined.
(Mathematical equation available in full paper)
where Re is the resistivity of the sand when all the pores are filled with brine, Rw the resistivity of the brine, and F a formation resistivity factor. F appeared to be a function of the type and character of the formation, and varied among other properties with the porosity of the reservoir rock. A reasonably accurate relationship was found between the porosity and density. Thus, knowing the porosity of the sand in question, a fair estimate of the value of F may be given by the empirical relationship,
(Mathematical equation available in full paper)
where n is the porosity fraction of the sand. The value of m was found to range between 1.and 2.

Correlation Between Porosity and the Electrical Properties of Some Deep Sea Sediments
Correlation Between Porosity and the Electrical Properties of Some Deep Sea Sediments Cores were taken from the Tyrrhenian abyssal plain, and the mass physical properties of these cores were correlated with the' electrical formation factor.
The sampler used was a wide-diameter sphincter corer and a special analysis bench (Fig. 1) was developed the following measurements were taken:porosity,wet (bulle) density andelectrical resistivity (formation factor).
The well known linear relationship between porosity and wet (bulk) density was controlled (Fig. 2). From the results of 10 cores, the following regression was found:
d = 2.60 - 0.0158n
where d is wet density and n is porosity. By plotting the formation factor vs porosity, derived from2,500 measurements made on cores collected in the Tyrrhenian Sea, several regression curves were obtained.
Reservoir Characterisation Through Joint Interpretation of EM, Seismic, and Well Log Data
Authors: MacGregor Lucy , Harris Peter , Walls Joel D. 
Published: October 2008

Abstract
Improved reservoir reservoir management and production optimisation demands require accurate characterisation of reservoir properties and their changes through time. Advances in geophysical data acquisition and interpretation have led to significant improvements in the remote imaging of earth structure and properties. However, when only a single data type is considered, ambiguities in the interpretation can remain. Here we will concentrate on three contrasting methods: surface seismic, marine controlled source electromagnetic (CSEM) and well-log data.
It is clear that a careful combination of all three data types can supply information that is not available, or is unreliable from any one data type alone. By integrating complementary sources of information and exploiting the strengths of each, estimates of rock and fluid properties such as gas saturation and porosity can be obtained with greater confidence than from any one data type alone. We illustrate this using an example based on the Luva discovery in the Norwegian sea.

Introduction
There are a range of physical parameters we can use to investigate the earth and properties of fluids within it. Well logs provide a high resolution measurement of the properties of a reservoir and the surrounding strata, however properties can only be determined in a small area local to the well. Often a measurement of reservoir properties across the extent of a field are desirable for reservoir management or production optimization and for this we must turn to remote sensing methods. In the well logging industry both electric and acoustic properties are routinely collected and analysed to study lithology, reservoir properties and the properties of fluids within them: it would be almost unthinkable to collect one data type without collecting the other, since this would result in an incomplete dataset that left gaps in our understanding of the reservoir and surrounding strata.
Until recently the same logic has not been applied in geophysical surveying and data analysis. Seismic methods, sensitive to acoustic properties only, have been the primary tools used in exploration, reservoir appraisal and monitoring. These methods are extremely powerful. Seismic data are commonly used to provide images of the sub-surface, and develop high resolution geological models of structure and stratigraphy. Amplitude variation with offset (AVO) and inversion for acoustic and elastic impedance may also be used to constrain properties such as elastic moduli and density. However seismic data alone in many situations cannot give a complete picture of the reservoir.
Polyester Moorings - Is Insert Recovery & Testing The Best Way To Determine Rope Integrity?
Authors: Ayers Ray R. , O&apos;Hear Nick 
Published: October 2008

Abstract
This technical paper addresses the value of regulatory requirements to recover and test 15-meter inserts from polyester mooring systems for production systems in the Gulf of Mexico. The authors have been working on a MMS-sponsored project to determining the Accuracy of Polyester Subrope Damage Detection by ROV Inspection, and Assessment of Remaining Rope Strength and Life.
Typical samples of subropes used to comprise 15-meter mooring rope inserts for polyester-based mooring systems have been exposed to the equivalent cyclic motions of 20 Hurricane Katrinas, and then the ropes were tested to failure. Results were compared to tests results from the same subropes not exposed to 20 Katrinas. There appears to be little if any rope decline in rope integrity, even if one Katrina-type hurricane scores a direct hit each and every year for the 20-year life of the mooring system.

Introduction

Background
In March 2007, the MMS contracted Stress Engineering Services, Inc. assisted by TTI, Ltd., to evaluate the accuracy and effectiveness of polyester subrope damage detection processes following hurricanes and other events (i.e., loop current) that exceed the 100-year design criteria for offshore structures. ROV inspections are used by the offshore industry to detect damage to polyester mooring systems and estimate remaining fatigue life if damage is found. This work addresses permanently moored floating production systems.

Approach
The fundamental question is: " What are the best ways to ensure the structural integrity of a polyester rope mooring system over the life of the project??? The specific objective for the MMS was to evaluate the accuracy of non-invasive damage-detection methods. Toward meeting this objective, the following issues were considered for polyester rope mooring systems:Structural mechanicsFactors that reduce structural integrityQualification for serviceCharacteristics of structural damageAssessment of current and new methods for determining fitness for serviceThe final report to the MMS (Reference 1) documents the complete set of findings from the work
DW RUPE: A New Deepwater Pipeline Repair Capability for the Gulf of Mexico and Other Deepwater Regions
Authors: Ayers Ray R. , Hoysan Steve , Rebello Armando , Gage Eric , Stark Mike 
Published: October 2008

Abstract
Described herein is a chronology for developing a deepwater pipeline repair system and cooperative ownership group for affecting emergency repairs of damaged pipelines. Using a Joint Industry Project (JIP) funding model, technology development started in 2004, and continued as Hurricanes Katrina and Rita hit in 2005, and resulted in the formation of DW RUPE - Pipelines Co-Ownership Group in May of 2007. Included in this paper is a description of the repair methods developed, and repair tools being procured and developed for affecting 10 to 24 inch ANSI pipeline repairs in 1,000 to 10,000 feet of water. A recently-developed spreadsheet-based pipe lifting analysis laptop computing tool is described for use in planning pipe lifting and cutting operations for a specific emergency pipeline repair operation in deep water.

Background on the Formation of DW RUPE
In 2004 Phase 1 of a JIP was formed to develop a low CAPEX emergency repair capability for pipelines and flowlines in water depths in the 1,000-10,000 ft range, in the US Gulf of Mexico. Stress Subsea, Inc. (SSI) performed a Failure Mode and Effects Analysis, conducted interviews with suppliers and operators and included input from the JIP Steering Committee.

Phase 1 JIP Conclusions
As a result from DW RUPE, Phase 1, the following conclusions were drawn for export pipelines:The probability of needing a deepwater repair is low, but the consequences resulting from pipeline damage are high. Because of this, the project agreed upon pursuing a low CAPEX repair solution, recognizing the need to minimize capital expenditures since the probabilities of occurrence are low.The most likely damage types are wet and dry buckles caused by anchor snags (the DW RUPE shallower water depth range is 1,000 ft., hence anchoring damage is still a consideration).Potential repair solutions for a low CAPEX pipeline repair and a low CAPEX flowline repair are different.Traditionally a leak clamp and a spool piece connector set are needed for each pipe size. The project pursued a new paradigm of adapting and employing full structural clamps in place of connectors. This allows two clamps to be used in a spool piece repair or one of the structural clamps to be used alone for a pinhole leak from a cracked weld. Two clamps serve the same function as two connectors and a clamp (Pipeline Repair), thus reducing the CAPEX investment for inventory.Cracked welds are the most likely cause for pinhole leaks. Full structural clamps are advised to arrest crack propagation (Pipeline Repair).
ACG Jackets Design and Fabrication
Authors: Ciezarek Richard , Cormack Archie , Penman Allan David , Mackie Richard , Tate Geoff 
Published: October 2008

Abstract
The ACG field is located in the Azerbaijan sector of the Caspian Sea approximately 130 km east of Baku, in water depths varying between 118m and 176m.
As part of the ACG Full Field Development (FFD) (see Figure 1), six barge launched jackets suitable for floatover topsides, plus associated drilling templates and foundation piles were designed and fabricated. Jacket loadout weights varied between 13,200 te and 16,700 te and the total pile weight, for all six structures, was approximately 44,000 te. Each jacket structure supports operating topsides weights of between 18,000 te and 24,000 te.
This paper explains the development of jacket design and fabrication capability in Baku. It also highlights the production line approach to the design and fabrication of the jackets and the challenges that were overcome to successfully deliver this part of the ACG FFD project in Azerbaijan.
The information will be of interest and value to those who face similar challenges in newly emerging energy markets and need to build up design or fabrication capability in other countries. It may also be helpful to those considering a production line approach to design and fabrication in order to optimise the delivery of major projects.
The detailed design for all six jackets was completed in London and Baku between September 2001 and September 2006; this was followed by post design support to both the fabricator and installation contractor. Key drivers for the size, weight and configuration of the jackets, templates and foundation piles are explained in this paper.
Construction of the jackets was executed in Baku between March 2002 and May 2007. The execution strategy for this work is explained with details of in-country upgrades of the fabrication yard, training of local personnel, fabrication schedules, specifications of steel, in-country rolling and erection roll up methods. The benefits of a production line of jackets are given in terms of procurement and logistics, re-use of construction and installation aids, lessons learned and the reduction in site queries, all leading to continuous improvement in productivity and schedule.
ACG Phase 3 Subsea Water Injection Scheme
Authors: Richmond Adrian , Barralet Peter 
Published: October 2008

Abstract
The third phase of the Azeri, Chirag, Gunashli (ACG) Project for Azerbaijan in the Caspian Sea develops the Deep Water Gunashli (DWG) area of the ACG reservoir, approximately 130km East of Baku. The DWG reservoir is highly pressure depleted due to extensive production from existing facilities adjacent to the reservoir. The provision of six pre-drilled subsea water injection wells optimises oil recovery over the field life. The subsea water injection scheme supports the production of 20% of the ACG Phase 3 reserves, for 10% of the total capital outlay.
In this paper, details are given of the facilities design, fabrication and installation and how delivery challenges to Azerbaijan have been overcome, including key lessons learned.
ACG Phase 3 topsides and jackets delivery adopted the same production line approach that was used in earlier phases, cloning the previous topsides and jackets. Subsea facilities had never been successfully utilised in the Caspian. The solution was to establish a production line based on extensive experience of subsea projects in the North Sea and utilising existing Company contracts with subsea vendors as the foundation. The use of established Company North Sea contracts for Phase 3 subsea builds on existing subsea market sector and technical experience, and allows future leverage with contractor performance and life of field support. The strategy that emerged has been successful and resulted in design and fabrication in Europe with transportation to Azerbaijan for installation.
To date the ACG Phase 3 subsea facilities have been successfully designed, fabricated and transported to Azerbaijan. Two of the three manifolds have been installed and the third manifold is planned to be installed in the first half of 2008. This is an industry first in the Caspian Sea, overcoming significant delivery and infrastructure constraints.

Introduction
ACG Phase 3 sanctioned scope included a subsea water injection scheme, the first planned subsea development in the Caspian. This subsea water injection scheme supports the production of approximately 200 MMstb. Due to pre-production of the target reservoirs to both the NW and SE of the DWG area by the previous developments at Shallow Water Gunashli and Chirag, approximately 1000 psi depletion will have occurred prior to first oil in 2008. Therefore early pressure support and recovery by water injection is critically important to achieve economic production rates and reserves recovery, and to limit producing gas/oil ratio to acceptable levels. The provision of pre-drilled subsea water injection wells enabled pressure support to commence immediately from first oil and allow drilling to initially focus on oil production.
How Subsea Processing Impacts Flow Assurance and Field Architecture in Ultra Deepwater
Authors: Saint-Marcoux Jean-Francois , Fontfreyde Thomas 
Published: October 2008

Abstract
Subsea processing covers different functions: flow boosting, gas-liquid separation, gas-oil-water (and sand) separation, and gas compression. These functions offer increasing opportunities along with increasing levels of complexity, and timeframe.
Subsea processing offers new possibilities for flow assurance and production practices. Accordingly, this will modify field architecture, as we know it. All components in the chain from subsea to surface will be affected: manifolds, flowlines, subsea templates, and risers. Noticeably, this will also affect the service and construction industry that will have to adapt to these new requirements.
The paper will describe the flow assurance options made available with flow boosting, gas-liquid, gas-oil-water separation and screen current flowlines and risers options to identify how they are likely to evolve to meet the requirements of subsea processing in ultra-deepwater.

Introduction
For oil producing fields, subsea processing can be classified primarily into flow boosting, gas-liquid separation, and gas-oil-water separation. Subsea compression is applicable primarily to gas producing fields, and at this juncture considered for relatively shallow water projects and not for deepwater or ultra-deepwater. This paper concentrates on ultra-deepwater and therefore subsea compression is not developed further, even though production of gas at elevated pressure can be beneficial as evidenced by Compressed Natural Gas (CNG) concepts.
This paper successively includes a review of oil production subsea processing, a typical ultra-deepwater case, and how the available technology of risers and flowlines covers the needs of these new features.

Subsea Processing
Oil production requires heavy topsides production equipment. This equipment includes the oil production trains, the associated gas compressors for gaslift and gas compression, the water injection system, power generation systems, storage, utilities, and living quarters. The combined weight of all these systems is quite large (typically 25 000T for a 200 000 BOPD FPU). The impact of subsea processing on the size of the topsides is limited and the benefit is not to be gained from a drastic reduction of topsides but from additional production.
Additional production can be achieved through two main technologies:Flow boosting: increase of pressure of the oil-and-gas wellfluid by a multiphase pumpSeparation of the gas from the liquid phase (water and oil) and pumping in liquid phase of the well fluid
A typical oil production train includes three separators in series. The pressure stages are optimized to meet the oil specification such as the Reid Vapor Pressure (RVP). A typical high pressure separator operates in the range of 500 psi (35 bar). As water depth increases, the benefit of subsea processing increases for a given tubing size (usually 5-1/2??).
The Offshore Petroleum Industry in Atlantic Canada - A Regional Overview
Authors: Barnes Paul 
Published: October 2008

Abstract
This paper will give an overview of current and planned future offshore exploration, development and production activity taking place off the east coast of Canada. It will also cover other items of interest occurring in that area including industry related research and development, recent changes in government policy and future growth potential of the industry. Information provided in this paper will be of interest to petroleum supply/service companies wishing to market their goods and services in this region of Canada as it will identify what producers are active in this area and possible future growth opportunities. In addition, the information provided on petroleum related research and development taking place and being applied in the region for offshore development and production would be of interest to a technical audience wishing to apply such research and development to other producing areas.

Introduction
Atlantic Canada is the eastern region of Canada that is comprised of four provinces - New Brunswick, Prince Edward Island, Nova Scotia and Newfoundland and Labrador. The Atlantic Canada offshore oil and gas industry refers to the oil and natural gas exploration, development and production industry off the east coast of Canada. At this time, all offshore petroleum industry activity is taking place offshore Nova Scotia and Newfoundland and Labrador. Fig. 1 shows the Newfoundland and Labrador and Nova Scotia offshore areas.
Functional Verification of the Worlds First Full Field Subsea Separation System - TIORA
Authors: Mogseth Gro 
Published: October 2008

Abstract
The dream of separating water from hydrocarbons on the sea floor is becoming a reality with StatoilHydro's Tordis IOR -Increased Oil Recovery - project in the North Sea. FMC Technologies has delivered the world's first full field subsea separation system, named TIORA, which was brought on-stream at the end of 2007. StatoilHydro expects to improve the Tordis field's recovery rate from 49 to 55 percent - an additional oil production of 35 million barrels.
To ensure success FMC Technologies has invested in a comprehensive test program, beyond the standard subsea functional and mechanical integration testing, to verify right functionality and minimum start-up time. Since the Tordis subsea separation system introduces new types of equipment and functionality in a subsea field development, FMC has performed extended functional testing to secure the technical integrity of the system.
The tests performed were categorized as follows:Technology QualificationsFactory Acceptance Tests (FAT)Extended Factory Acceptance Tests for sub-systems (EFAT)System Operation Test (SOT)System Integration Test (SIT)
These tests also included testing of the two main operational functions:Closed-loop control of the water injection and multiphase pumpsFunction and control of the de-sanding operations through an extended technology qualification
In the System Operation Test, the 2,3 MW water injection and multiphase pumps from Framo Engineering were connected to the FMC control system in order to run a complete functional test of the pump operation. Since separator level and pressure are important parameters in the pumps control algorithms, an online dynamic process simulator was connected to the real subsea instruments communicating through the FMC subsea control module. The control loops were then closed and the tests were performed as close to reality as possible.
For the extended robustness verification of the de-sanding operations, spare modules were combined with purpose-built equipment in a test rig simulating expected operating conditions. In addition to testing, the platform operators used the test facilities for familiarization with the operation of the equipment.
The lessons learned through the additional functional verification tests provided a significant contribution to a smooth and efficient start-up and operation of the subsea separation system, and also resulted in important feedback for use in the design of next-generation subsea processing systems.
A softer lesson learned is that tests need to be planned in an overall test road map to ensure that all tests provide a combined better knowledge of the system - without degrading the resulting overall system performance.