bluuebunny/crossref_metadata_2025_split huggingface dataset:
Economics & Case Study of a Change to Big Bore Wells
Authors: Landrum William R. 
Published: October 2008

Abstract
This paper describes a field development program from its inception through the first year of production. Part way through the construction phase, engineering evaluations indicated that a change in the development plan to all big bore wells would accelerate oil production and improve project economics. Approval was gained for the change in basis of design from smaller well bores to all big bore wells. Actual production data was tracked. Well performance and economic analyses were performed to post audit field and well results. The value of changing to big bore wells was then easily quantified.
In the early engineering and construction phase of the development, nodal analyses showed that production well performance could be increased from a well rate of 20,000 BOPD (3180 m3/d) to more than 30,000 BOPD (4770 m3/d) with a change from 5-1/2" tubing and tree to a larger 7" size. A reservoir model was run with production ramp-up to plateau to feed into an economics model. At the same time, operational concerns over the size change were voiced and probabilistic economic simulations were run to take into account the potential for additional trouble or down-time accompanying operations during the installation of the larger 7" equipment. Economics were favorable.
Approval was granted by management and a special resolution passed by the Unit Technical Committee to change the basis of design from 5-1/2" tubing and tree to 7". This change proved to be a major factor in the successful start-up and profitability of the development. Production wells began producing at a rate of 40,000 BOPD (6360 m3/d) each, with one exceeding 46,000 BOPD (7313 m3/d). This would not have been possible with the smaller tubing size. The net present value (NPV) from accelerated production improved overall project economics by more than $108 million due to the change to big bore wells.

Field Information
The Heidrun Field in the Haltenbanken Area offshore mid-Norway, was discovered in the Spring of 1985. The field lies 118 mi (190 km) from the Norwegian coast in 1150' (350 m) of water. The appraisal program of 7 wells proved oil and gas in the 3 major reservoir units of the Middle Jurassic Fangst Group and the Lower Jurassic BÅt Group which is differentiated into the Tilje and Ã?re formations. The field contains 2.785 billion STB (443 million Sm3) of oil in place, 1 billion STB (159 million Sm3) of recoverable oil, 1.592 billion SCF (45 billion Sm3) of gas in a gas cap, plus more than 1.386 billion SCF (39 billion Sm3) of solution gas. The field contains a 656' (200 m) oil column and extends over an area of 9400 acres (38 square km).
The Heidrun Field was mapped based on 3D seismic data acquired in 1986. A variety of methods and types of data were employed in generating the geologic model of the field including wavelet processing of the 3D seismic data to enhance the reservoir description, extensive correlation studies, and field studies on outcrops of analogous sediments exposed in East Greenland.
Sassan Field A Case of A Major Offshore Production Operation in the Persian Gulf
Authors: Dietzel Norman E. , Freeburg Edward A. 
Published: October 2008

Abstract
Lavan Petroleum Company (LAPCO) was formed in April 1965 as a joint structure operating company, one-half owned by the National Iranian Oil Company and one-half owned equally by four American companies: Atlantic Richfield Company, Murphy Oil Corporation, Sun Oil Company, and Union Oil Company of California. On August 31, 1965, Well 2S-l was spudded in one of three offshore Persian Gulf tracts explored by LAPC9, and later proved to be the discovery well of the Sassan Field with no existing production operations and only a drilling and exploration staff, LAPCO embarked on a program to design, install, and commission this major offshore production operation. The resulting facilities, capable of producing and handling 220,000 barrels of oil per day, were on stream by June 1968. Consultants and contractors were used for nearly all phases of evaluation, engineering, design, and construction.
The development plan for Sassan Field included several unique features more or less forced upon LAPCO by the Axtent and location of the field. These include:
1. Individual well structures and flowlines, in water" depths of 68 to 100 feet.
2. High throughput of live oil with no surge capacity on the offshore flow station.
3. An 88 mile, 22 inch diameter pipeline between the field and Lavan Island through water depths up to 306 feet.
This paper emphasizes the importance of effective planning to achieve a rapid development and installation of a major crude producing, handling, and loading complex, both onshore and offshore. It also demonstrates that even the best of planning cannot anticipate all eventualities and that some delays and extra costs are unpredictable in a project of this magnitude.

Introduction
The story of the Sassan Field may be said to date from the 5th century A. D., for at that time its namesake, the Sassanian Dynasty, was at the height of its ruling power over all of ancient Persia. Fifteen centuries later, the "modern" Sassan story began when a Joint Structure Agreement became effective February 13, 1965 between the National Iranian Oil Company (NIOC) and four American oil companies: Atlantic Richfield Company (the coordinator), Murphy Oil Corporation, Sun Oil Company, and Union Oil Company of California. This Agreement led to the creation in April 1965 of Lavan Petroleum company (LAPCO) as the operator. This new company was charged with the exploration, development, and exploitation of three tracts in the Persian Gulf totaling about 8,000 square kilometers. (See Illustration No.1.)
LAPCO's initial well, No. 2S-l, was spudded on August 31, 1965, and in November, a drill stem test yielded crude oil from a formation at 7968 feet which was eventually tested at 7788barrels of oil per day (BOPD). through 3-1/2 inch drill pipe and clearly established this as a commercial well. By December when the well was completed, there was little doubt that LAPCO would soon be developing a major offshore production operation.
Quantifying Fluid Prediction Using Angle-Dependent Inversion Measured Against Log Fluid Substitutions
Authors: Anderson James W. , Bogaards Mark A. 
Published: October 2008

Abstract
A Bright spot prospect was identified using 2D and 3D seismic. Due to the isolation of this prospect from existing infrastructure it is critical to be able to predict the type of hydrocarbon likely to be present. The approach taken to quantify hydrocarbon type included the following steps:reprocess a 2D seismic line which connects the well control to the prospect,use the well to model the response of different pore fluids in the reservoir quality sands,perform incident angle dependant inversions of the 2D seismic,statistically quantify and compare the results from the prospect with the model results,use the fluid probability at the prospect in the project risk assessment.
We know that normal incidence seismic data is the response to the acoustic impedance, AI, of the geologic layers. However, at non-zero incident angles, the seismic data is the response to the elastic impedance1, EI, of the geologic layers. Because of the inherent pitfalls of using amplitude variation with offset2, AVO, a new approach was taken to quantify the fluid at the prospect. First, a pre-stack time migration of a 2D seismic line was created followed by near and far angle stacks. AI and EI volumes are then generated for the respective angle stacks. This process is called angle dependent inversion, ADI. AI and EI values are extracted for each CDP within the prospect.
Log-based fluid substitution3,4,5 models are created to establish a range of AI and EI values for reservoir quality sands. Each model is displayed as a probability distribution function, PDF and compared to the extracted ADI values. The results indicate that it is unlikely that the prospect sand is brine filled. The most probable hydrocarbon in the prospect reservoir is gas.

Introduction
A deepwater Gulf of Mexico prospect was generated in which high amplitude seismic events were used to define the areal extent of a potential reservoir. The location of the prospect is over 30 miles from the nearest host platform. It was assumed that a single subsea completion would be used to develop a discovery. However, it was quickly realized that given the estimated volume of the reservoir and the tie back distance a gas discovery would be very commercial while an oil discovery would be equivalent to a dry hole. Trend analysis of the surrounding fields was not conclusive in predicting the most likely hydrocarbon type at the prospect. Therefore, a study was conducted in which modeled acoustic and elastic impedance for varying reservoir fluids were compared to extracted values from near and far angle seismic inversions in an attempt to predict the fluid type in the prospect.
Although the prospect was mapped using a 3D data set it was concluded that a single 2D seismic line through the prospect would be sufficient to make the fluid prediction. A recent-vintage 2D line was selected that went through the center of the prospect and within 500 feet of our primary well control (Well 1).
Setting Up New Ventures in West Africa
Authors: Lorenz Jeannot C. , Lorenz Alexis R. 
Published: October 2008

Abstract
The main application for this paper is for businesses looking to locate in the region to gain a basic understanding of the general requirements to be successful in West Africa, primarily in Angola. The secondary application is for various businesses to use the paper as a framework for evaluating whether suppliers in the region are indeed, well established and thus able to successfully operate and fulfill contracts. It will, in particular, address the challenges of building an organization where the political, economic and social cultures are quite different than that of the United States. The paper will review the necessary skill set of key personnel within the organization, which is needed to operate successfully in a diverse environment. We will also examine the challenges of lack of infrastructure with regard to conducting daily business and maintaining operations as well as winning contracts.

New Discoveries in West Africa
The latest figures for West Africa indicate a bounty of deepwater opportunities. Nigeria currently produces two million barrels per day and recent discoveries will push the figures even higher. The Congo Basin is also proving to be quite impressive. With the Chevron, Elf, BP/Amoco and Exxon deep water discoveries in Angola, the region has never looked so promising as noted in the Financial Times newspaper earlier this year. The paper cited Angola as "one of the world's most exciting oil frontiers and two-thirds of deep water exploration wells have struck oil, compared to a historical world average of closer to 15 percent." Consultants have predicted that Angola's current production of 800,000 bpd will increase to 1.4 million bpd by the 2005. Others have predicted that production could rise to 2.5 million bpd by 2015 surpassing Nigeria to become Africa's largest oil producer.
Even with the lure of the huge potential in West Africa, many companies still shy away from the region. It is not without good cause that companies are reticent about starting up operations in West Africa. Despite the trepidation, companies can and do thrive in the region. The aim of this paper is to provide sound advice for you and your company to succeed in this exciting region of the world.

The Pioneers and the Emerging Market
In the beginning, there are always those brave souls willing to venture forth to set-up shop in the far corners of the world. The first task for the pioneer is to verify market information available through various commercial sources.
Testing the market is the primary mission for the pioneer. If the products or services do not add value to the market, there is no point in going any further. Testing the market is not a simple procedure in Angola. One must take time talking with national oil company managers, potential clients and suppliers. Flying in for a week and flying out will not render the needed information.
Trends In The Steels Used In Merchant Shipbuilding
Authors: Crum Frank J. 
Published: October 2008

ABSTRACT
With the increase in the size of modern merchant vessels, as well as changes in design and increased plate thicknesses, there has been a growing interest in the use of higher strength steels for ship construction. The history of hull steel specifications following the advent of welded construction is discussed, together with present American Bureau of Shipping requirements for both ordinary and higher strength steels. Some precautions that are considered particularly necessary when welding on higher strength steels are also presented. Since mobile offshore drilling units are now being classed by the Bureau, the owners and designers of such structures may find the discussions included in this paper of interest.

INTRODUCTION
As everyone closely connected with the shipbuilding industry is aware, the present trend toward the use of higher strength hull steel is increasing and it appears to be increasing at a rather rapid rate. As the size of merchant ships continues to grow and as the size and number of hatch openings in cargo vessels and ore carriers increase, it has become necessary to use heavier plating of ordinary strength steel, which in some cases approaches 2", in order to meet strength requirements. There has been reluctance to use plating of excessive thickness since investigations on the brittle fracture problem have indicated that, in addition to metallurgical considerations, there are "size effects" which adversely influence notch toughness as the thickness of the plating is increased.
The primary advantage of higher strength steels is that they allow a reduction in plate thickness which tends to minimize "size effects" and which results in a ship of lighter weight and greater load-carrying capacity for a given size vessel. Depending on the needs or wishes of individual owners and the size or type of vessel they choose to build other advantages may be (1) greater speed (2) lower fuel consumption(3) a smaller size propulsion unit or (4) improved stability through reduction of top-side weight. The use of lighter gage plating during construction offers the further advantages of (1) lighter sub-assemblies to handle (2) less man-hours of welding and (3) lower electrode consumption. Some of these economic advantages are offset however to some degree by the higher cost of the steel and electrodes, possible replacement difficulties and the refinements or improvements that may be necessary in design, workmanship and inspection. It is, therefore a decision of individual owners and designers whether to use higher strength steels and to what extent.
Although higher strength steels are now being used rather extensively they are not entirely new in merchant ship construction and have been used in Naval vessels for a number of years. Higher strength steels were used with satisfactory results on such vessels as the SS "United States" built in 1952 on the SS "France" and several ore-oil carriers built in 1962, and on a few vessels strengthened for navigation in ice.
Prediction of Static Bearing Capacity from Wave Equation Analysis
Authors: Coyle Harry M. , Bartoskewitz Richard E. , Lowery Lee L. 
Published: October 2008

ABSTRACT
The purpose of this paper is to present the results of a study which involves the prediction of the static bearing capacity of a pile from a wave equation analysis of piling behavior. Recently developed soil parameters including point damping, friction damping and quake are used in the computer solutions of the wave equation analysis. Also, the wave equation program is modified so that velocity may be raised to a power less than 1 in order to insure constant damping effects.
Curves of total static soil resistance at the time of driving vs pile penetration resistance in blows per foot are developed. Different curves are generated for different distributions of total soil resistance between the side of the pile and the tip and for varied soil parameters. These curves are compared with similar curves developed using E. A. L. Smith's recommended soil parameters.
Using the computed curves and the knowledge of pile penetration resistance during the last foot of driving, the static bearing capacity of the pile is predicted. These values of pile capacity are compared to actual values determined full-scale static load tests made in the field.

INTRODUCTION
In 1960, Smith7 presented a mathematical model to simulate pile-soil interaction. At the same time he proposed a numerical method for analysis of piling behavior based upon the one-dimensional wave equation. Smith' s model idealized the pile as a series of masses and springs as shown in Fig. 1. The load deformation characteristics of the soil as shown in Fig. 2 are described the parameters Ru, Q, J, J1 and V, where
(available in full paper)
The total soil resistance mobilized during dynamic loading was given by Smith as:
(available in full paper)
Research personnel at Texas A&M later modified Smith's original equation so that the velocity term is raised to a power [N]. 3,4,6 Eq. 1 is rewritten as:
(available in full paper)
When Smith's paper was presented in 1960, factual information concerning the magnitudes of the damping constants and J1 were virtually unavailable smith recommended parameters of 0.15 and 0.05 for J and J1, respectively. He also recommended a value of 0.10 for the parameter Q. Smith based his recommendations mainly on the strength of his own field experience with the piling behavior problem.
Recent research conducted at Texas A&M has resulted in What is believed to be more representative values for the parameters Q, J1 and J.3,4,6 The values obtained are presented in Table 1. There values are based mainly on the work of Korb,4 which involved small-scale dynamic and static pile loading tests in a variety of soils.

Parameter Study Using Field Test Data
The computer program for solving the one-dimensional wave equation is used to generate a curve relating total static soil resistance at the time of driving to the driving resistance expressed in blows per foot.
Case History: Decommissioning, Reefing, and Reuse of Gulf of Mexico Platform Complex
Authors: Hakam Aly , Thornton Win 
Published: October 2008

Abstract
During the creation of the Galveston 189 platform complex artificial reef several firsts were achieved: a permanent shallow water, low profile reef; a permanent reef site with easy access for the general public; and the largest diamond wire cut made in the Gulf of Mexico. In addition to these firsts, the procedures required during the decommissioning of an offshore platform, the severing techniques used and the variety of disposal options available for obsolete offshore oil and gas structures are reviewed.

Introduction
One requirement in every offshore oil and gas lease, in State or Federal waters, is the removal of the structure at the end of its useful life. In the best case, the end of life for a platform is defined as 15 months after production activities on that lease cease. The removal of an offshore facility is a multi-phase process. The first activities are the planning and permitting. Generally the planning and permitting phases will take a couple of weeks; in special cases, such as offshore California, they will require years of regulatory activities. Once the permits are received, the bid packages evaluated, and contracts in place the work onsite starts. The wells are permanently plugged. The pipelines are then cleaned and capped, and sometimes even removed. The production equipment is flushed and made gas free. The structure is removed. And finally the site is trawled with a shrimp net to prove the site is clear of objects on the seafloor.
The reefing of oil and gas platforms in the Gulf of Mexico is considered a win-win solution for the operator, regulators and the environment. When a platform is installed offshore an artificial reef is automatically created. By providing a method to maintain the hard bottom strata created by the platform the existing marine life around the platform stays virtually intact. The regulatory agencies involved are the Minerals Management Service (MMS), Army Corps of Engineers (COE), United States Coast Guard (USCG) and State Wildlife Departments. These regulators have control over the location, placement and materials that are reefed. The operators have the opportunity to reduce removal costs and liability. Upon acceptance of the created reef the ownership of the reefed materials transfers to the local State agency. To assist in the maintenance of the reef sites and outreach programs the operators typically donate one-half of the cost savings to the Artificial Reef Program in the State that they are working with. For the GA 189 platform complex the reef donation amount was $300,000.

Background
The Galveston 189 platform complex standing in 60' of water approximately 12 miles off Galveston, Texas was installed in 1981. The complex consisted of a four-pile main production platform, GA 189 B, set up to produce 10 mmcf/d and 2,000 bo/d. The production platform was bridge connected to two satellite structures, GA 189 C and GA 189 D. The GA 189 C platform was a four pile well protector with a minimal deck.