bluuebunny/crossref_metadata_2025_split huggingface dataset:
Feasibility Study of a Dual Density Mud System for Deepwater Drilling Operations
Authors: Lopes Clovis A. , Bourgoyne Adam  T. 
Published: October 2008

Abstract
Recent successful exploration efforts in deep waters have heightened interest in-developing oil and gas reservoirs on the continental slope. Leases have been obtained in water depths up to 10,000 ft with a requirement that they be drilled within the next decade. Use of current techniques to drill these leases will require extremely large floating drilling units and large diameter marine riser systems. This paper presents the results of a feasibility study of the use of an automated gas-lift system for a marine riser that will maintain the hydrostatic pressure in the subsea well-head equal to the hydrostatic pressure of the seawater at the seafloor. Hydrostatic control of abnormal formation pressure could still -be maintained by a weighted mud system that is not gas cut below the seafloor. Such a dual density mud system could reduce drilling costs by reducing the number of casing strings required to drill the well and by reducing the diameter requirements of the marine riser and subsea blowout preventers. The system would have the advantages of riserless drilling without giving up the well control advantages of a closed, weighted mud system.
A steady-state numerical model was developed that can be used to determine the gas injection requirements needed to achieve a desired dual density configuration. The numerical model was verified through tests conducted in a 6,000 foot research well. Once verified, the model was used to define the gas requirements and practical limits of a marine gas-lift system based on estimated additional costs of gas compression and nitrogen membrane filters. The practical limits are presented in terms of maximum mud density, water depth, and riser diameter combinations. The paper also discusses the operational changes that would be required for various drilling procedures such as making a connection, running casing, kick detection, and well control operations.

Introduction
Drilling operations in waters deeper than 3,000 ft are increasing throughout the world, and the industry is now looking into the challenges imposed by ultra-deep waters (&gt;7,000 ft).
One of these challenges comes from the fact that the current technology relies on the use of marine risers to extend the well up to the drilling vessel, so the mud and tools can get in and out of the well in much the same way that is done on land However. when drilling with mud densities in excess of sea water density, the exposed sediments in the open borehole see a pressure tending to cause formation fracture that is affected by the full column of drilling fluid all the way up to the drilling vessel. The overburden pressure of the sediments tending to help resist formation breakdown is generated by sediment densities in excess of seawater hydrostatic only from the mud line down.
The Challenges of Lufeng 22-1 Development
Authors: Millmaker Allan , Yu Liang , Adlam John 
Published: October 2008

1.0 ABSTRACT
This paper describes the challenges involved with the development, design and fabrication of the FPSO and related facilities for the development of the Lufeng 22-1 field.
The field will be developed using five subsea wells connected to the FPSO by two flexible flowline risers. The five horizontal wells will be drilled through single template and completed with subsea production trees mounted with electrically driven booster pumps, installed to provide the means of artificial lift.
The FPSO is based on a multipurpose shuttle tanker (MST) fitted with a processing plant which has a capacity of 125,000 bpd of gross fluid volume, and 60,000 bpd of crude oil. The storage capacity of the vessel is 640.000 bbls. The individual well rates are expected to reach 25,000 bpd of fluid and 15,000 bpd of oil.
The Lufeng crude oil is paraffinic, low sulphur with a high wax content. The API gravity is 31.1" and the pour point 43°C requiring the oil to be stored at elevated temperature above wax appearance temperature of 62°C. The mooring system is a Submerged Turret Production (STP) system which is disconnectable in extreme weather conditions.

2.0 INTRODUCTION
Lufeng 22-1 is a small oil field located remote from existing infrastructure in the Pearl River Mouth basin in 333 meter of water approximately 265 km Southeast of Hong Kong in the south China Sea. See figure 1 - Lufeng 22-1 Location.
The field, owned by Statoil (75%) and CNOOC (25%), was discovered in 1986 and two further appraisal wells were drilled in 1989. Extensive testing was performed on the appraisal wells with rates of up to 24,000 bpd achieved and approximately 1.6 mmbbls of oil produced. The tests confirmed the high porosity of the sandstone reservoir and indicated the need for horizontal well technology to delay water influx and maximise oil recovery. The field is being developed with five horizontal wells with horizontal section lengths between 480 and 1800 meters.
The field is marginal with considerable uncertainties in the reservoir production parameters. The anticipated costs of a conventional stand alone development do not make the field economically viable and alternative model was therefore required.
The oil reserves to be recovered are estimated to be ca. 30 mmbbls representing a recovery factor of approximately 25% of the original oil in place. The environmental conditions in the South China Sea also contribute to the difficulties experienced by potential field developments in the area. Typhoons are frequent and the area is affected by solitons (subsurface waves generated by tidal variations).
The system chosen to develop the field is an FPSO based on the multipurpose shuttle tanker MST Munin. Facilities are provided on day rate lease. See figure 2 - Lufeng 22-1 Field Development Arrangement.
Vertical Connection Used as Tie-in System for Rigid Pipeline
Authors: Moreira C.C. , Puppim L.A. , Braga V.R. , Marins J.R. , Haugen F. 
Published: October 2008

Abstract
An attractive alternative to the use of flexible pipe flowlines is the use of rigid pipe flowlines. This is especially true in deep water giant fields or marginal fields, where the distance from floating production units to the wells is often several kilometers.
Deepwater diverless tie-ins have a significant impact in the overall economics of the field development, and the selection of the tie-in method is a part of the critical path.
This paper describes the studies conducted to evaluate and select a diverless tie-in system for the connection between the manifolds and rigid pipelines, and between rigid pipelines and flexible risers.

Introduction
In previous developments of deep water fields in the Campos Basin, Brazil, in water depths up to 1000 m, flexible flowline between christmas-trees or manifolds and floating production units have been used as a standard. The use of flexible pipelines allowed for rapid development of new fields, and the ability to recover and re-use flexible pipelines reduced their capital cost. Several connections systems has been used, including horizontal pull-ins, lay-away installations, and most recently the Vertical Connection System(VCS), addressed in ref. 1.
Field development in Brazil is now moving into deeper waters and more marginal fields, requiring longer flowlines. As the flow line length increases the cost effectiveness of flexible pipelines is reduced when compared to rigid pipelines. In a new scenario of Albacora field, two(2) subsea production manifolds will be connected to rigid pipelines.
Nating in flexible risers. The use of rigid pipelines requires a new diverless connection system to be selected.
To evaluate alternative tie-in methods for rigid pipelines at the manifolds and risers, a study was performed to select the most economical and feasible tie-in system. Consideration was given to the resources available in Brazil, the operational experience and the technical soundness of the system, and the ability to meet the project schedule and budget

Scenario
In Albacora Field - phase I1 (fig. l), four (4) subsea production manifolds and one (1) subsea water injection manifold will be tied in to the production unit, the FPSO P-3 1 Vidal de Negreiros.
Each production manifold will receive the production of eight (8) wells. The schematic of the production manifolds (fig. 2) shows the following:One (1) 8" ID production header,One (1) 8" ID service header,One (1) 4" ID production test header,One(1) 4" ID gas lift header.
To allow pig passage (required to prevent paraffin formation) the production header and the service header are connected in a pigging loop, as well as the production test header and the gas lift header.
External Acoustic Sensors and Instruments for the Detection of Sand in Oil and Gas Wells
Authors: Brown Gerald K. 
Published: October 2008

Abstract
From the earliest days of oil and gas production, solids mixed with the flowing medum have caused problems. The origins of these solids (sand) can be attributed to formation particles, solids introduced into the well such as drilling mud and frac sand, corrosion products (metal loss) and any other solids flowing through a system. With the ever changing methods of well drilling and completion the probability of sand is much higher today. In addition, the financial payback time is shorter so that more flow must be attained in a quicker and shorter time frame.
If the production of sand is not minimized, formation damage can occur, downhole well equipment can be damaged, surface production equipment can be damaged and plugging of surface equipment can occur. The damage to the equipment alone can be expensive as well as the loss of product during downtime. In addition, the possibility of failures due to sand erosion can be catastrophic as produced fluids and gases can escape into the land, sea or atmosphere when a failure occurs due to erosion.
There are many methods of sand control. In order to control the sand production it is necessary to have an early indication of the sand flow and its intensity. This paper will give a brief overview of the history of sand monitoring and the latest technology available for the detection of sand and the detection of the damage (erosion) that sand can cause.

Introduction
In the production of oil and gas a borehole is drilled through to a strata of rock that has enough porosity to allow the flow of liquids and gases from the rock into the borehole. This liquid or gas, or combination of liquid and gas, then flows, or is pumped up, through the borehole to the surface.
Solids mixed in with the produced fluids and gases indicate that either the formation is breaking down or other solids such as fractionation solids, drilling mud, construction debris, scale, or corrosion products are flowing up the well bore. In any case this flow of sand is undesirable.
Breakdown of the formation can lead to unstable flow and formation damage that can eventually lead to loss of production and even abandonment of the well.
When other solids are flowing with the product we usually see an initial heavy flow of solids in a new well as these solids introduced as a result of drilling, formation fracturing, cementing, and production completion construction that have accumulated in the well bore flow to the surface. Once the initial amount of solids are clean from the well, the flow of solids is usually stabilized until such time as the well is adjusted to flow at such a high rate that the solids from the formation (sands) break loose and flow up the well bore. In addition, after a period of time produced scales and corrosion products can also flow to the surface.
Campos Basin: 20 Years of Subsea and Marine Hardware Evolution
Authors: Formigli J. , Porciuncula S. 
Published: October 2008

Abstract
Since 1977, when the first oil was produced to a floating rig through a test tree inside the BOP Stack (Enchova-01 well), around 30 Floating Production Systems were installed in Campos Basin, offshore Brazil. Due to the prolific geological conditions of this province, production ranges from shallow (100m) up to deep waters (1027m), demanding significant breakthroughs in the applied subsea and marine production equipment which were used for the exploitation of these fields.
This paper presents the technical evolution of the associated hardware, as manifolds, umbilicals, flowlines, monobuoys and mooring systems, highlighting some milestones which made viable the achievement of the present water depth limits of oil and gas production. Their field performance is also shown and gives a real solid background for the extension of the water depth limits up to 2000m for future production systems under design/construction, not only in Campos Basin but also for other offshore sites around the world.

Introduction
Campos Basin is located offshore Rio de Janeiro State, on the Southeast Region of Brazil. Its area covers approximately 100sq. Km ranging from 20m up to 3400m Water Depth (WD).
Environmental conditions can be considered as relative "benign"; 100 year return period conditions are:wind: 37mls;waves: 14m height/l2s period;surface current: 2.0m/s;bottom (1 000m WD): 0.8m/s.
The continental shelf may be described as a flat surface with a very slight inclination (constant gradient around l°) up to water depths around 200m. Beyond this border, the gradient increases gradually up to values around 10° or more in some locations, featuring the so called continental slope. Ocean floor is generally smooth all over Campos Basin but some local canyons in water depths ranging from 400m till 1500m are outstanding. Clay sediments are predominant at the mud line with dispersed occurrences of live and dead deep water corals.
The first field discovered at Campos Basin was Garoupa in 1974 through the wildcat 1-RJS-9A; in a short period of time, Namorado and Enchova fields were also discovered: these were the former evidences this area could be a prolific oil province. Based on this assumption, it was necessary to improve the exploratory efforts. At the same time, Brazilian political and economical situation demanded a significant increase in the domestic oil production using the fastest pace as possible.
The traditional conception to produce fields with similar characteristics - a stationary jacket platform (eventually installed over a template with pre-drilled wells) - would demand more than half a decade for producing the first oil.
Campos Basin: An evaluation about 20 years of operations
Authors: Vargas R.J.B. , Coutinho C.M. 
Published: October 2008

Abstract
Campos Basin started his production in 13 august 1977 with 10 thousand barrels of oil per day from the well EN-01 which produced to a semi submersible platform. Nowadays Campos Basin operations comprises 28 production platforms, 1500 wells (30% in operation), 17 drilling rigs, and 3,950 kilometers of flowlines, pipelines, and umbilicals. Present daily production is 610 thousand barrels of oil and 11 million cubic meters of natural gas.
The evolution of the production in Campos Basin was supported by investments in exploration and production, in deep water technology developments, and continuous management improvement. This evolution is summarized in several management programs focusing production growth, cost reduction and general progress of other performance indexes.
The main management programs supporting an increasing productivity added to the current development projects portfolio in deep waters, anticipates a daily production of 1.3 million barrels of oil and 22 million cubic meters of natural gas in next five years, with significant improvement in all economics indexes.

Introduction
Campos Basin is located in the north coast of Rio de Janeiro State comprising an area of more than 100.000 km2. The producing oil fields are among 70 and 140 km far from the seashore, and are located in front of Campos, Macae and Cabo Frio cities (Figure 1). This is the main production area in Brazil. It contributes with almost 70% of the total oil production and about 60% of the total natural gas production. A11 the production in this basin is exclusively done by PETROBUS. Formerly by the Southeast Production District, which was succeeded by the Southeast Production Region, and latterly by the E&P-BC (Campos Basin Exploration and Production). E&P-BC is now the division of PETROBRAS that is in charge of developing and exploring this area. The headquarters of E&P-BC are located in Macae city, that is almost 200 km distant from Rio de Janeiro city. Both cities are connected by a highway known as BR- I0 I, that makes part of the extensive national highway complex. Besides it's headquarters, PETROBRAS, have in Macae an oil treatment station, stock tanks and pumping stations. The latter is responsible for the displacement of 45% of the total crude oilproduced in Campos Basin. This crude oil is displaced to the company refineries in Rio de Janeiro, Sào Paulo and Minas Gerais States, through a network of pipelines. In the same area is located a liquefied petroleum gas plant, which uses natural gas as primary input. It has also a gas compression station that recompresses all the gas received from the offshore platforms and displaces it through two gas pipelines to the same refineries.
The Eight Best H2S Removal Methods in Federal Waters, Offshore California
Authors: Konczvald A. 
Published: October 2008

Abstract
In Federal waters offshore California, there are currently many desulfurization techniques implemented on 23 platforms to address different H, S levels as a function of daily production rates. This paper describes the individual effectiveness by design criteria, repair history, and performance under overload. It is intended to help future platform operators in the selection of a gas sweetening technique based on raw gas volume and H, S contamination. It also describes two methods applicable in other offshore areas, but abandoned recently in the Pacific Federal waters due to strict air quality restrictions and costly emission source-offset requirements.

Introduction
This is the first attempt to evaluate the current H,S removal technologies in offshore California. (See table 1 on platform characteristics and the H,S contamination range of 3 ppm - 18,000 ppm). The criteria for evaluation are: removal efficiency, safety, and economics. The author noticed that low H,S levels can be treated efficiently with regenerable sluny methods, while high gas contamination may need robust, amine type processes. The paper also includes an example for total pre-flare sour gas sweetening. The summary contains a suggested selection processes for the right technology.
1. Platform Elly, Beta Field(Shell/CalResources, LLC After 6 years of water reinjection of up to 20,000 BPD, the underground chemical reaction yielded increasing H,S content in produced gas. In 1988, when hydrogen sulfide levels reached 14 ppm, Shell Western Exploration & Production, Inc. (SWEPI) initiated the Petrolite SX-600 injection for fuel gas sweetening. In 1990, H2S contamination in raw gas reached 19 ppm, while in 1992 routinely exceeded 28 ppm, causing the sweetened fuel gas readings to exceed the 3 ppm maximum admissible H2S level posted by the South Coast Air Quality Management District' in the Los Angeles air basin. Excursion data triggered by system dynamics show that during the sweetening process part of the mercaptans became trapped in the oil phase, causing instrumental readings of 1-7 ppm H2S in the sweet fuel gas for turbines and heater trehters:
H2S + SX-600 ?=? (mercaptans + gas + H2S)
At this point, SWEPI decided to implement the Sulfa Treat technology to comply with county, State, and Federal requirements for the Pacific Outer Continental Shelf (Pacific OCS).
The concept consists of two beds operating in series, while one is approaching the allowable depletion level the other is replaced and kept in stand-by mode to correct excessive volume fluctuations during kicks in the wells. The catalyst is non-regenerable; it must be barged offshore. The end product is classified environmentally friendly by the EPA and by California Title 22 criteria, therefore, it can be disposed of in local landfills. The piping, skids, accessories, and the two catalytic beds weigh 90,000 lbs.
MMS 1200: Cooperation on a Subsea Multiphase Flow Meter Application
Authors: Caetano E.F. , Pinheiro J.A.S.F. , Moreira C.C. , Farestvedt L. 
Published: October 2008

Abstract
PETROBRAS (Brazil) and FLIJENTA (Norway and USA) are since beginning of 1996 working on this multiphase flow metering route development under a Technological Cooperation Agreement. This Cooperation involves flow meters that are making use of innovative arrangements and physical principles, and are being applied to oil-in-water monitoring, water-in-oil monitoring and multiphase (oil, water and gas) flow metering, which also includes a subsea version. All the meters are going to be prior tested at the PETROBRAS Test Site for Multiphase Equipment - a test site, built onshore (Atalia, city of Aracaju) that allows performing highly representative tests, when compared with-actual production installations - in the qualification process aiming at the usage at the PETROBRAS fields. The FLIJENTA conception for a subsea multiphase flow meter (SMFM 1000) will be combined with the PETROBRAS' experience associated to system architecture adequacy to the subsea deep waters deployment and then resulting on the MMS-1200 - a subsea retrievable multiphase meter module. Such module - a guidelineless conception - will be installed on a subsea production manifold (08 wells, 450 m. of water depth, WD, 5 km away from the host FPSO - floating production, storage and off-loading vessel) in the deep water Albacora field in the Campos Basin (April 1997). This paper presents the major characteristics and benefits of the multiphase metering technology and focus on the MMS-1200 description, its development phases, test planning, associated time tables and results obtained up to date.

Introduction
The main purpose of this multiphase flow metering technological route when applied to be untreated usually produced fluids (e.g., oil, gas, water and occurring solids), without the need to separate them first, is to determine the phases fractions and their associated flow rates. The route is based on multiphase flow meters, which are devices, usually non-intrusive to the flow, that by the combined usage of selected physical principles and flow signal interpretation - under the knowledge of the main physical principles governing multiphase flows - are able to determine the phases (e.g., oil, gas and water) fractions and their actual flow rates.
Currently, the trend in the industry is to increase the distance from wellhead to SPVs (stationary production unit). As this distance grows, the costs and problems of traditional systems grow; whereas for multiphase meters the cost is fixed and, in general, the performance improves as the distance grows (due to an increase in wellhead pressure). The shorter well test duration typical of a multiphase meter allows reservoir and operations engineers to have more current data for field management.
The oil and gas reserves in deep waters (400 to 1,000 m) and ultra-deep waters (1,000 to 2,000 m) off Brazil correspond to almost 64 % of the total Brazilian oil and natural gas liquid (NGL).