bluuebunny/crossref_metadata_2025_split huggingface dataset:
Status of the Cantarell Field Development Program: An Overview
Authors: Limón-Hernández T. , Ponce G. Garza , Aguiñaga C. Lechuga 
Published: October 2008

Abstract
The Cantarell Complex is the largest field in México and the sixth largest in the world, with original proven reserves of over 17 billion barrels of oil. It started producing in 1981 and, through 1995, produced approximately one million barrels per day.
In 1996, a redevelopment project was started to increase reserves, more than double oil production, utilize all the gas by adding sufficient compression and process capacity, and modernize the existing facilities to improve operational safety and efficiency. Overall, the design, construction, and installation of these facilities are nearly 80 percent complete.
This technical paper provides an overview of the project, a summary of the current status, and a discussion of major project achievements to date.

Introduction
The Cantarell field, located about 80 kilometers (km) offshore of the Yucatan Peninsula in the Bay of Campeche, Mexico (see Figure 1: Location of Cantarell Oil Field), is the largest oil field in Mexico.
The Cantarell field was discovered in 1976 and has a surface area of 162 square kilometers (km2). It is composed of four major fields: Akal, Nohoch, Chac, and Kutz, in addition to the reserves in the newly discovered deeper Sihil field.
These fields comprise an anticline oriented northeast to southwest. The Akal block is the largest of the complex with 91 percent of 35 billion barrels of original oil volume, followed by Nohoch, Kutz, and Chac. The average depth for the Akal field is estimated at 2,300 meters (m) below sea level.
The Cantarell crude is classified as heavy, with a density varying between 19 ° and 22 ° API and containing sulfur compounds. The producing zones consist of different geological formations that are highly fractured with abundant vugs due to dissolution, providing superlative productive capacity.
The exploitation of Cantarell began in June 1979, and reached a production peak of 1.156 million barrels of oil per day (bpd) in April 1981. By 1986, the reservoir pressure of 270 kg/cm2). had decreased by 60 percent to 172 kg/cm2. Pemex installed a lift gas system which stabilized production at approximately one million bpd until 1995.
In 1996 an increase in production began as a result of the Cantarell Project. Production reached 1.4 million bpd in 1997. By early 1999, the production in most of the wells was facilitated by lift gas, yet the bottom hole pressure had further decreased to 112 kg/cm2.
In the beginning of Cantarell field, wells were capable of producing an average of 31,000 bpd. Currently, the average production per well has been reduced to a little more than 7,000 bpd. The relationship between reservoir pressure and oil production is shown in Figure 2: Cantarell Field Production and Bottom Hole Pressure. The pressure-production history of the field indicates that each kg/cm2 of pressure reduction in the reservoir corresponds to a production loss of more than 120 bpd per well.
Remotely Operated Vehicle Work Capabilities in Support of Deepwater Operations
Authors: Jolly R.D. , Moles P.A. 
Published: October 2008

Abstract
Advancing in front of the Oil and Gas industry to deepwater, ROV service companies are steadily improving the tools necessary to support subsea developments. The key tool that permits intervention at depth is the ROV. Combined with custom designed tools, the ROV system is a critical component for subsea operations. And just as the depths have increased, so has the need for intervention by a system that is forced to be more capable, reliable, flexible, and weather tolerant.

Introduction
The dramatic and rapid expansion in deepwater developments has been driven by the attractiveness of deepwater reservoirs despite the technical and commercial challenges that they pose. In order to drill, develop and produce these deepwater reservoirs a number of key ROV and ROV related capabilities have had to undergo, and continue to undergo, considerable improvements. In addition, an entire new set of capabilities has to be developed. This paper will take a closer look at the technical improvements that are necessary to carry out productive work in deep and ultra deepwater.
The basic tool for carrying out this work is the remotely operated vehicle, or ROV, a capability that has been supporting the Oil and Gas (O&G) sector since the late 70's. Over the last 20 years the ROV has progressed from a quirky combination of incompatible and generally unreliable components to a workhorse essential to supporting the industry's deepwater work requirements.
Existing ROV and tool capabilities for deepwater operations, new developments in deepwater ROVs and tooling, improvements in launch and recovery systems and the present and future of AUV/UUV capabilities will be reviewed.

Existing ROV Capabilities for Deepwater Operations.
Initially, Workclass ROVs introduced in the late 70's into the O&G industry worked predominantly in shallow water. In 1983 when Shell initiated its deepwater drilling off the U.S. East Coast, Shell committed to carrying out the drilling support tasks using a ROV. Up to that time a manned submersible, Pisces, had supported the Discoverer Seven Seas' deepwater operations. O&G ROVs had never operated in depths approaching the 2000+msw Shell was planning to drill in. In fact, most O&G ROV operations were in less than 500 msw. Shell's program represented a paradigm shift in the support of deepwater operations.
International Submarine Engineering (ISE) developed the Hydra 2500 in conjunction with Oceaneering and the Hydra 2500 system ushered in the era of deepwater O&G ROVs. The Hydra 2500's first working dive was in 2100msw and over the next 9 years carried out over 2000 dives with an average dive depth of almost 1850 meters, with a deepest dive of 2310msw. The Hydra 2500 proved conclusively that an ROV could operate reliably and effectively in deepwater and produce dramatic cost savings to the overall drilling program. The Hydra 2500 established the baseline for all future deepwater ROV operations in the offshore industry.
Design Of An Automatic Marine Corer
Authors: Bailey Edmond I. , Davis Grayum L. , Henderson H.O. 
Published: October 2008

ABSTRACT
Upon request of several geophysical organizations, a program was initiated at Texas A&M U. under the Sea Grant Program to design a self-contained automatic seafloor setting corer which willextract up to 50 ft of continuous undisturbed. core,operate in depths up to 1,000 ft of water,core in hard as well as soft material andbe as compact as possible to facilitate shipboard handling.
This program was partially funded by Oceanonics, Inc., Houston, Tex. The SEACORE 50 will extract a 3-in. diameter core 49.5 ft long in 11 sections. The unit is octagonal in cross section measuring 6 ft side to side and is 12 ft in height. When the Unit reaches the seafloor, four legs fold down and level the unit on slopes of up to 15 °. The unit weighs 10,000 Ib dry, 8,000 Ib in water, and is lowered to the seafloor by a single power-tension cable. An automatic control system is continued in the unit with shipside manual control available at any time. A drill pipe fitted with a ring-type core bit is rotated under a considerable thrust load while water is pumped down the center of the drill pipe to wash the cuttings back up the annulus. This water is routed through the double-walled bottom joint around the core barrel so that the sample is not washed. A square rod extending from the top of the coring unit retains the rotation of the core barrel. This square rod also supports a piston in thecore barrel, thus affecting "fixed piston" coring. A hydraulic powerhead produces 1,000 ft-lb of torque and 6, 000 Ib of thrust or pull.

INTRODUCTION
The tools and techniques used today in ocean mining and exploration for obtaining undisturbed samples of the seafloor leave something to be desired. They require either logistic support from divers on the bottom or must be operated from a large surface ship with multipoint anchoring.
Upon the request of several marine engineering concerns, a program was initiated at Texas A&M U. under the Sea Grant Program and partially funded by Oceanonics, Inc., Houston, to design a self-contained automatic seafloor setting coring device which will be capable of obtaining a 3-in. diameter core at least 50 ft long in depths of up to 1,000 ft of water. The recovered sample should be at least 90 percent of the amount drilled. The device should be activated with a power package on the ocean floor and supplied by a single umbilical cable from the surface vessel. It should be capable of rapid penetration and withdrawal to circumvent anchor spreads. It should be as compact as possible to facilitate ease of shipboard handling. The device should employ both rotary and push-type operations with interchangeable coring bits to handle all types of sediments and must employ the fixed-piston.
Problems And Solutions In Large Scale Evaporation
Authors: Ennis Charles E. 
Published: October 2008

Of all the desalting capacity in commission today, 97.7% employs one of the distillation or evaporative processes. This is rather remarkable when we consider the theoretical basis of distillation as opposed to competitive processes. Distillation, first of all, is burdened with a relatively high potential energy loss in the heat of vaporization hen compared to the heat at fusion, which sets the energy threshold for input to the freezing processes. Membrane processes, on the other hand, don';t even require a change of state and so enjoy a rather significant advantage.
In spite of the preeminence of the distillation processes, however, they still produce water fairly expensively and they still are not attractive enough to support construction of a really large desalting plant. Today, I';d like to review with you some of the problems associated with the distillation processes and some of the solutions that have been proposed to these problems.
First, let';s define the evaporative processes. The most widely used process today is the multi-stage flash, sometimes referred to as the "MSF" or "SEMS" system. This process has its basis in the fact that water boils at lower temperatures as the pressure on the water. is reduced. In an MSF system, the salt water passes through a number of chambers in which pressure is maintained at progressively lower temperatures. in each of these chambers, a portion of the brine boils or "flashes". This flashed vapor is condensed on tubes which carry the incoming feed brine counter currently through the chambers.
Vertical tube distillation, sometimes referred to as "LTV" or "VTE", also depends for efficiency on the boiling point-pressure relationship. In a vertical tube plant, the salt water falls through a number of vertical tubes which are surrounded by steam. As the steam condenses on the outer surface of the tubes, the brine is heated in the tubes and a portion of the brine flashes to vapor. The condensed steam becomes the product for that effect and the flashed vapor becomes the heating steam for the next succeeding effect. The unflashed brine from the first effect becomes the feed brine to the second effect and so on. A plant will consist of a number of effects in series so that most of the input energy, supplied as steam to the first effect, can be utilized.
The multi-effect, multi-stage distillation process uses. a series of two or more multistage flash plants as separate effects to combine benefits of both processes. The principal advantage of this arrangement is that scaling is minimized by exposing the lowest concentration of brine to the highest temperatures and then subjecting the increasingly concentrated brine to successively lower temperatures.
Vapor compression distillation operates on the principle that, when a vapor is compressed, its temperature and pressure increase as the volume decreases. Compression heats water vapor, which then condenses on tubes containing the incoming brine.
Wave Pressures On The Underside Of A Horizontal Platform
Authors: Denson Keith H. , Priest Melville S. 
Published: October 2008

ABSTRACT
The destructive effects of shallow water wave action on the underside of horizontal floors, decks, and platforms is evident from the inspection of hurricane damage. In order to provide some knowledge of the pressure distribution under such conditions, a laboratory study was made. Results are generalized through the use of dimensionless parameters and are presented in graphical form. These graphs show maximum and minimum relative pressure intensity and distribution of relative pressure intensity along the underside of the platform, in the general direction of wave motion, for various conditions of relative wave height, relative clearance, relative width, and relative length.

INTRODUCTION
Inspection of structural damage due to hurricanes along the Gulf Coast has revealed that horizontal floors, decks, and platforms are susceptible to severe damage by shallow water wave action on the underside. In order to gain some knowledge as to pressure intensities associated with such conditions, a laboratory study was undertaken. Although hurricane conditions could not be simulated, the action of shallow water waves on a small scale structure provides useful information as to the nature of the problem.
The study was designed to reveal the separate effects of wave height, clearance above still water surface elevation, width of structure, length of structure, and still water depth on pressure intensity along the underside of. the structure, in the general direction of wave motion. This was done by varying each quantity, except depth, from the value associated with a set of common or reference conditions. The results are generalized insofar as possible through the use of dimensionless parameters, length ratios with stillwater depth as the common quantity.
There is reason to believe that the motion of a large, storm wave through relatively shallow water may be more nearly that of a solitary wave than that of a wave in an oscillatory wave train. Proceeding on this premise, the waves generated for this study were sufficiently far apart that they were considered to be independent of one another. This means that, for the purposes of this study, such quantities as wave period and wave length are not considered to be significant.

DIMENSIONAL CONSIDERATIONS
A rather common structural problem along coasts exposed to hurricanes is that having to do with pressure intensity on the rectangular, horizontal underside of floors, decks, and platforms as a result of shallow water wave action. If the study is limited to cases in which a centerline of the rectangular underside is parallel to the general direction of wave motion, the physical quantities which appear to enter the problem are those necessary to describe the pressure intensity, the location at which pressure intensity is determined, the characteristics of the water, the characteristics of the waves, the spatial relation of structure to water, and the geometry of the structure.
Brutus Project Overview: "Challenges and Results"
Authors: Rainey R.M. 
Published: October 2008

Abstract
Brutus is Shell's fifth tension leg platform (TLP) installed in the Gulf of Mexico. It is located in 2985 feet of water in Green Canyon Block 158 and is 100% owned by Shell. The estimated ultimate recovery is about 250 million barrels of oil equivalent and the total cost is expected to be less than $750 MM including pipelines and wells but excluding lease costs. Brutus is expected to be Shell's next major producer in the Gulf of Mexico with design rates of 100,000 barrels of oil per day and 150 million cubic feet of gas per day.
This paper will provide a general overview of the Brutus project. This will include a comparison of similarities and differences between Brutus and other Shell TLPs. The Brutus project has integrated learnings, designs and components from many previous projects while also adding capability and technology for deepwater hub processing, hydrocarbon dewpoint control of the export gas, and a combination use drilling/production riser system.
The Brutus project has significantly improved overall performance. When benchmarked against comparable projects in Shell, the cost is 17% lower and the schedule from construction funding to first oil is 7 months shorter than previous best in class. This has been accomplished while maintaining Shell's focus on quality and HSE. The early uptime performance of the facility after start-up has also been outstanding with facility uptime averaging 98% over the first five months.

Introduction
The Brutus platform is located approximately 155 miles south-southwest of New Orleans, Louisiana in the Green Canyon 158 block as shown on the map in Figure 1. The platform is an 8-slot Tension Leg Platform (TLP) in 2985 feet of water. A photograph of the completed platform just after installation is shown in Figure 2. Major components of the platform are shown in Figure 3 with a brief description of size, weight, and fabricator. The hull and deck configuration is similar to the Mars and Ram/Powell TLPs. However, the hull has been upgraded to provide additional displacement capacity with total displacement of 54,700 short tons and significant additions have been made for hub capabilities and gas processing equipment.
The platform is designed to handle tieback of up to five subsea fields. The facilities are designed for a throughput capacity of 100,000 BOPD and 150 MMCFD through two separate processing trains. Oil is transported 25.5 miles through a 20" pipeline to the South Timbalier 301 B Platform where it ties into the Amberjack gathering system. Gas is transported 24 miles through a 20" pipeline to the Ship Shoal 332 A Platform where it ties into the Manta Ray gathering system.
A high level project schedule is provided in Figure 4.

System Selection
An extensive system selection process was applied at Brutus with numerous type and sizes of systems considered. This included Spars, Ship based systems, subsea, and TLPs.
Thermal Behavior of Complex Geometric Configurations in Dry Tree Risers
Authors: Golczynski T.S. , Brown T.S. 
Published: October 2008

Abstract
Predicting the thermal behavior of conventional dry tree riser configurations is relatively simple, using standard heat transfer models. However, as developments move into deeper waters, the conventional dry tree riser configurations may no longer provide adequate thermal performance. The steady state arrival temperatures are often below the Wax Appearance Temperature and the cooldown times to hydrate formation can be dramatically reduced. Costly and complex riser configurations such as insulation, offset tubing, and/or fluid circulation may be required to provide adequate thermal behavior. More complex riser designs must take into account natural convection and radiation effects, changes in material properties along the length of the riser, and in general consider more than just a one-dimensional equation to accurately model thermal behavior.
Traditional heat transfer correlations have a large uncertainty associated with these effects or do not account for them at all. This analysis addresses various riser configurations, predicts the resulting heat transfer properties based on more rigorous calculation methods, and calculates the thermal behavior of each system.

Introduction
Dry trees are traditionally not expected to pose significant flow assurance challenges. In the event of wax or hydrate formation, coiled tubing or some other remediation technique could be used, due to relatively easy access to the tubing string. However, for deepwater developments, the flow assurance challenges are quite significant. Steady state issues with wax deposition and transient issues with hydrate formation are prevalent. Along with the structural integrity issues that deeper waters present, flow assurance concerns often require a more complex riser design to provide suitable thermal operation.
The analysis presented here focuses on three main aspects of riser design. First, the effect of using offset tubing in the riser is evaluated. Offset tubing may be required to keep casing diameters small, while accommodating large auxiliary lines. By moving the tubing closer to the casing wall, the conduction pathway for heat transfer is reduced, degrading the overall heat transfer coefficient (U-value) and cooldown times for the system as a whole. The impact of offset tubing is most pronounced for solid annulus materials, since the presence of liquids and gases creates convection currents that more evenly distribute the temperature throughout the riser cross-section.
Second, most heat transfer correlations accurately predict the thermal behavior for conduction, but may not include or model correctly the effects of convection and radiation, which will greatly alter the thermal behavior of the system. Moreover, the impact of convection and radiation for gas systems is sensitive to the pressure of the gas. In deepwater developments, the hydrostatic pressure of the gas will result in different pressures at the base of the riser as compared to the top of the riser. This inherently makes the thermal analysis much more difficult.