bluuebunny/crossref_metadata_2025_split huggingface dataset:
Extended Reach Drilling From Platform Irene
Authors: Mueller M.D. , Quintana J.M. , Bunyak M.J. 
Published: October 2008

ABSTRACT
Two wells extending out over two miles have been drilled by Union Oil Company of California (Unocal) from Platform Irene in the Pt. Pedernales Field, offshore California. These wells hold the record for the two longest reach wells on the West Coast.
Several wells around the world have been drilled beyond two miles, but none have accomplished this feat at such shallow, true vertical depths. The average angles (from rotary table to TD) for Platform Irene wells A-16 and A-17 are 70.9° and 68.2°, respectively.
This paper will present to the industry the concepts of a "Negative Weight Well" and "Drag Risk Analysis", and will focus on the innovative technology used to drill and complete a high drag well. The successful drilling and completion of these wells has enabled the future recovery of millions of barrels of oil originally expected to be produced from a second platform.

INTRODUCTION
Unocal and its partners, Gulf (now Chevron) and Superior (now Mobil), acquired Federal Lease OCS P-0441 in OCS Sale #53 in May, 1981. The Pt. Pedernales field was discovered in November, 1982 with the drilling of Unocal OCS P-0441 #1. Platform Irene was set in August, 1985 and the first well was spud in April, 1986. In March, 1987, tracts P-0437, P-0438, P-0440, P-0441, P-0444, and P-0510 were combined to form the Pt. Pedernales Unit consisting of seven partners.
Platform Irene is located in 242' of water approximately 4.5 miles from nearest land and 60 miles west-northwest of Santa Barbara, California.
Figure 1 depicts Platform Irene's location relative to the California coastline.

FIELD DEVELOPMENT
A viscous 15.8° API crude oil and gas are produced from the Miocene Monterey formation. The Monterey varies several hundred feet in thickness and consists of vertically fractured, thin-bedded and interlaminated cherts, dolomites, and shales.
Production was initiated in April, 1987 at the rate of 10,500 BOPD, 0% cut. Peak production of 23,500 BOPD was achieved in August, 1987 after eleven development wells were acidized.
It was originally intended to develop the south-east portion of the reservoir with Platform Irene and set another structure, Platform Iris, approximately two miles to the north-west, to develop the rest of the field. The setting of Platform Iris became uneconomic s oil prices plummeted.

OBJECTIVES
By drilling the high angle, extended reach wells from Platform Irene, it was hoped that the following objectives would be achieved:The need for the high capital costs of a second platform would be eliminated.The near-horizontal well bores would intersect more vertical fractures and cut more formation.Prove that not only could a "Negative Weight Well" be drilled and completed, but that it could be accomplished in an economic manner.
Development of Automated Offshore Drilling System
Authors: Fujita H. , Sato M. , Shiraishi N. , Wakiya Y. , Tanaka S. 
Published: October 2008

ABSTRACT
The purpose of the project is to develop the "Automated Offshore Drilling System" and to establish its basic design.
Since 1984, research. investigation work. design. fabrication, and field test have been executed to develop the "Automated Offshore Drilling System" by Japan Ocean Industries Associations (JOIA), jointly with Mitsui Engineering & Shipbuilding CO., Ltd.(MES), and other member companies under the auspices of the Ministry of Trade & Industries (MIT!).
Field tests of prototype mud pulse MWD and demonstration tests of 1/2 (one-second) scaled pipe handling systems including racking system, top drive system, draw works, Auto Roughneck, Pipe Handler, etc. had been completed successfully.

INTRODUCTION
The oil & gas extraction from offshore fields has become one quarter(1/4) of the world product. This percentage is expected to increase, and the development targets of future offshore fields will move toward a harsher environmental area, i.e., deeper water and arctic areas.
On the other hand, "automation" is the demand of the times, in the industries and all human lives. however, the equipment and system on the drilling rigs seem to be far from automated. The major reason of the above is, the drilling operation strongly depends on experience and special skills of drilling crews. At the same time, a shortage of skilled drilling crews will become a critical issue.
The current low level of the day rates earned by offshore drilling rigs and the reduced level of drilling by oil companies, has reduced the R&D efforts. The oil companies and contractors are rather conservative, then the rigs with totally different drilling system such as National A10-32 are very few. Developments of robotic drill pipe handling unit such as Temco in Norway have not been succeeded.

R&D PROJECT
To meet the demands of the times, MITI has been promoting the "Highly efficient offshore oil & gas drilling project", to develop an "Automated Offshore Drilling System", and entrust its practice to JOIA.
This project, started in 1984, has a goal aimed atthe 1989 fiscal year to establish the basic design of the "Automated Offshore Drilling System". The project committee has been organized by JOIA with 12 member companies in Japan, to discuss the R &D work.
The philosophy of this project is to develop the "Automated Offshore Drilling System" as an extension of the present concept, the system can be applied to any type of existing drilling rigs with small modifications to some extent.
Among many sub-systems to be automated, the following five have been selected for this project:Central control &monitoring systemReal time measuring system (MWD)Mud control systemPipe handling systemBarge control system
Accurate Vertical Pile Installation by Using a Hydraulic Vibratory Hammer on the Arbroath Project
Authors: Ligterink A. , van Zandwijk C. , Middendorp P. 
Published: October 2008

Abstract
In the Summer of 1989 the Arbroath platform was installed on behalf of Amoco in the UK Sector of the North Sea. A part of the project involved the installation of two docking piles, for locating the platform accurately over the template, and four under-leg piles for giving initial stability to the platform, before the skirt piles had been driven.
The paper describes the use of a vibratory hammer, the ICE-14l2, during the installation of the docking and under-leg piles. It describes how the penetration by vibrator was predicted, and how during the initial stage of penetration, control was kept over the verticality of the pile. For the first time the pile inclination was measured continuously during penetration, providing the opportunity to correct the verticality as required. The paper highlights the principles and results of these measurements.
The paper concludes that the combination of vibratoryhammer and conventional hydraulic underwater hammer can be very effective for underwater pile installation. The pile verticality can be effectively controlled by continuous measuring of the pile inclination during vibration.

Introduction
A part of the Arbroath Project was the installation of two docking piles and four under-leg piles, all with an outside diameter of 1067 mm in addition to eight foundation skirt piles. The docking piles were required for an accurate positioning of the platform over the existing template, whereas the under-leg piles were needed to support the jacket during the actual piling and to avoid uneven settlements during driving and when standing unpiled in a Summer storm.
Because the verticality of some of the piles wasextremely important on this project and because of the uncertainty of the top soil layer, the piles were predriven with an ICE-14l2 vibratory hammer, and taken to final penetration by an IHC S-400 hydraulic hammer. Due to the water depth, the entire operation was performed under water.
To ensure the verticality during the initial penetration of the piles, two inclinometers were mounted on the vibratory hammer housing. Hard wiring ensured that the inclinations were read out on a display on deck of the semi submersible crane vessel.
Due to the smooth operation and because all piles were installed well within the tolerances, (the maximum pile out-of-verticality was only 0.75 degrees according to the instrumentation and 1.25 degrees according to a check by divers), the job was performed fully to the Client's satisfaction.

The Arbroath Pr01ect
The Arbroath project consisted of a 3300 tones platform, to be positioned with the aid of a crane vessel over a pre-installed sub sea wellhead template with a number of pre-drilled wells. The water depth at the locations was 93 m. The jacket was installed in 1989; the template having been installed 10 years earlier.
Ekofisk Reservoir Pressure Drops and Seabed Subsidence
Authors: Mes M.J. 
Published: October 2008

Summary
Phillips Petroleum company Norway has measured the progression of seabed subsidence of the offshore Ekofisk field monthly from March 1985 through the present using satellites and seafloor pressure gauges. Subsidence rates derived from satellite data for the period from March 1985 through April 1988 have been correlated with reservoir pressure drops to relate reservoir pressure decreases to increases in subsidence. The crystal portion of the compacting field may contribute most to the seabed subsidence at the 2/4 H platform, located near the central portion of the field. The arguments are described. We used a cause and effect analysis as a mathematical tool. We derived that most seabed subsidence occurs approximately four months after a change in reservoir pressure and a 7 month history of subsidence caused by a unit drop in reservoir pressure. Data are listed, the interpretation and analysis procedures are described, and the interpreted final results are presented which describe:Pressure drops near the center of the reservoir correlate best to the seabed subsidence in the central portion of the field.A contemporary relationship between reservoir void age and seabed subsidence rate can be used successfully to relate reservoir pressure drops to subsidence increases.A tool to estimate short term subsidence properties from reservoir pressure drops or vice versa.
The study concerns itself only with short term subsidence effects. For long term predictions Phillips Petroleum Company has developed very sophisticated computer models. A description of these models and the use there of are excluded from the scope of this paper.

INTRODUCTION
Phillips Petroleum Company Norway is the operator for the Ekofisk field. This field is located roughly in the middle of the North Sea. Several platforms, placed near the center of this field, are connected by bridges. This group of platforms is referred to as the Complex. The field was discovered in 1969 and has produced oil and gas since 1971. Subsidence of the Ekofisk field was discovered in November 1984.
Phillips Petroleum Company developed very sophisticated two and three dimensional computer models to simulate compaction and seabed subsidence. These models and their physical, geophysical and geological background were discussed in an 1988 Offshore Technology specialty session dedicated to Ekofisk Subsidence. (Most of the papers presented in that session can also be found in the Journal of Petroleum Technology, July 1989 Vol 41, no.7). These models, driven by reservoir pressure, are used amongst other, to predict long term subsidence. The work that is presented in this paper is very pragmatic and qualitative by comparison. Its purpose is to correlate contemporary short term pressure changes to short term seabed subsidence. In this sense its intention is to provide additional insight in the subsidence phenomena.
Axial Capacity of Offshore Piles in Clay
Authors: Karlsrud K. , Nadim F. 
Published: October 2008

ABSTRACT
The paper describes two main aspects related to axially loaded offshore piles in clay: methods to determine the local ultimate skin friction and effects of cyclic loading on axial pile capacity. A new 'NGI-method' for determination of ultimate skin friction is described in detail. The method is primarily based on predicting the ultimate skin friction from the state of effective stresses at onset of pile loading, coupled with untrained shear strength properties of severely remolded and reconsolidated clay as determined by direct simple shear tests. A software system for evaluating the response of an offshore pile is described. Based on a case study for piles in soft plastic clay, it is shown that the pile capacity is significantly reduced if the cyclic loads comprise a large portion of the design loads. The influence of pile length (flexibility) is also demonstrated.

INTRODUCTION
Significant efforts were made in the past decade to improve the methods of determining the axial capacity of offshore piles in clay. These include development of an extensive pile load test data base (Olson and Dennis1) and related statistical studies on the reliability of various common empirical design rules (Olson2, Tang3, Lacasse and Goulois 4); a number of large and small scale instrumented pile load testing programs and development of new theoretical models.
As a result of these efforts, the API-RP2A 5 design guidelines underwent a pronounced change in the 17th edition, where the undrained shear strength reduction factor, ?, was related to the in situ normalized untrained shear strength ratio, rather than the absolute value of the untrained strength. Furthermore, in the commentary to the 17th edition the necessity of separately evaluating the effects of pile length or flexibility and cyclic loading on the pile capacity was pointed out.
During the period 1980-84 the Norwegian Geotechnical Institute (NGI) undertook a comprehensive pile load testing program in an over consolidated clay deposit at the Haga test site, Karlsrud and Haugen 6,7 A total of 27 individual pile tests were carried out on 5 m long, heavily instrumented steel piles with a diameter of 15.4 cm. The pile loads covered a wide range of static and cyclic loading combinations, mostly in tension, but also in compression. Based on the results of these tests, various theoretical concepts and models were developed for analyzing the pile clay interaction during installation, reconsolidation and pile loading. This paper concentrates on two main aspects:Determination of the ultimate static skin friction after full set-up according to the "NGI-method", and comparison to API and some other empirical design rules.Determination of effects of cyclic loading on the axial capacity of offshore piles according to the computer model PAXCY developed by NGI.
Balmoral FPV: Three Years On
Authors: Harrington G.L. , Davis A.J. , McIntosh C.J. 
Published: October 2008

Abstract
The Balmoral Floating Production Vessel (FPV) has been on location in block 16/21 of the UKCS since August 1986. The Vessel has produced virtually continuously in some of the worst weather experienced in the North Sea for several years.
This paper presents the first 3 years of the operational 1ife of the Balmoral FPV. It describes the major plant items and how they have behaved in service. Weather sensitivity is discussed along with modifications which have been made.

Introduction
The Balmoral FPV was built in Sweden and arrived on location in August 1986. First oil came in late November of the same year and the rate gradually built up to plateau as wells were brought online. Figure 1 shows the production profile since startup. A description of the vessel, along with design criteria has been presented previously1. Briefly, the floating vesse1 acts as the production faci1ity to separate the gas, water and oil from 13 template and satellite wells. It is connected to the sub sea template by flexible risers. The facility also has the necessary equipment to perform work overs, drilling, water injection and gas lift.

Down hole/Gravel Pack/Sub sea
The Balmoral Field has been developed using 10 template and 3 satellite production wells and 6 satellite water injection wells - see Figure 2 for field location map. All the wells were comp1eted prior to the arriva1 of the FPV on location and startup of production. In addition, 2 further fields have been developed using the Balmoral FPV facilities: the Glamis field which consists of 2 satellite production wells and one satellite water injection well and the Blair field which consists of one satellite production we11. Production from these fields commenced in the summer of 1989.
Initially all of the Balmoral wells were gravel packed for the purposes of sand control. However during the completion of a satellite production well, the gravel pack resulted in such a significant reduction in productivity that the well was unable to meet its production target. As a result the gravel pack was pulled and the well recompleted without a gravel pack. In addition, there have been 2 gravel pack failures to date. These were due to chloride stress corrosion cracking of the wire wrapped screens induced by stimulations of the wells with HCl and HCl/HF acids. Subsequent to this new stimulation treatments have been designed based on acetic and HF acids.
Sand production from the wells is being monitored by the use of sand probes on the FPV although they have not proven to be very successful. At present the sand production rates are such that it does not constitute an operational problem. However should such a problem arise then serious consideration will be given to regravel packing these wells.
The Design and Operation of the "Not Normally Manned" Amethyst Gas Field
Authors: Maciver L.M. , Khatib H.M. 
Published: October 2008

ABSTRACT
The Amethyst Development incorporates a combination of well proven techniques in a novel manner to achieve a multi platform, remotely controlled gas field.
The field is located in the UK Sector of the Southern North Sea, some 40km offshore.
The reservoir is gas bearing with higher than average condensate yield. Its aerial extent is c. 106 square km requiring four platforms and up to 21 production wells to deplete it.
The fields will produce a peak rate of 250 MMSCFD of gas in the first contract year starting October 1990, followed by a peak rate of 300 MMSCFD for the subsequent six years of production. Thereafter production will decline as reserves are depleted. Daily condensate rate is expected to peak at 3.4 MBPD during the plateau period.
The development plan encapsulated a number of interesting features, such as onshore gas compression, onshore fiscal metering, full control and operation from the landfall terminal, all combining to achieve economy with enhanced safety.

INTRODUCTION
The Amethyst field was a first round UKCS license - its development was from the outset foreseen as an engineering challenge.
Some seventeen appraisal wells were drilled to establish the reservoir and various development studies were carried out in the quest for a viable investment. These early studies were centre on a conventional development approach, having an offshore gas gathering system (with unmanned satellites) and the requisite manning and gas compression facilities offshore.
This approach did not yield the necessary economic results, or indeed, offer the safest solution.
In 1986, a more target Ted approach to determine a development plan was established and key objectives set which focused on capital and operating cost reductions, simplification of the facilities, and improved safety, with utilization of the infrastructure at the landfall
This effort was successful and the development plan was given approval in June 1988.

THE DEVELOPMENT PLAN
The development plan as approved in June 1988 is shown in perspective view in Figure 1.
The adoption of this plan achieved the following key features:elimination of reliance on rotating equipment offshore during normal operation;multi-platform remote control from shore;minimal onboard platform facilities;remote spearing of 30 inch pipeline;power supply by sub sea cable;wet operation of pipeline with corrosion inhibitor;export of methanol from the landfall terminal by piggy-back pipeline;maximum utilization of landfall infrastructure;location of compression facilities onshore, some 5 years into field life;telecommunication by digital signal; use of a proprietary package for the field control system.
The Use and Application of Permanent Downhole Pressure Gauges in the Balmoral Field and Satellite Structures
Authors: Shepherd C.E. , Neve P. , Wilson D.C. 
Published: October 2008

ABSTRACT
Down hole gauges installed in Block 16/21 satellite wells have given invaluable real time data during extended well testing (Sterling and Blair) and have been extremely useful in gaining an understanding of Balmoral and Glamis well and reservoir behavior in the early stages of production.
The long term reliability of these systems has proved disappointing, highlighting the need for further engineering research and development in this area, particularly in sub-sea electrical connectors. It is hoped that experience gained with the reported systems will help others considering their use or those looking at further developments of down hole pressure systems.

INTRODUCTION
The Balmoral Field, located in Block 16/21 and discovered in 1975, received Government development approval in 1984 after extensive appraisal drilling. The field has been developed with 19 sub sea wells, 13 producers and 6 injectors (Figure 1). Ten of the production well s were drilled through a template and the remaining three are tied back to the template via subsea flow lines. All of the six injectors were completed sub sea and tied back to the template by flow lines.
Beneath the Balmoral Field, in fractured Devonian sandstone, lies the Sterling Field. Oil in Devonian sands was observed in a number of appraisal wells in the area and in 1986, well 16/21a-2 was completed and tied back to the Balmoral FPV for an extended well test. At the satisfactory conclusion of the test the well was recompleted as a Balmoral Paleocene producer.
In 1989 two separate satellite fields, Glamis and Blair, were tied back to the Balmoral template. The Glamis Field is in the Jurassic sands to the south west of the Balmoral Field and has been developed with two producers and one injector. The Blair Field is in Paleocene sands partially overlying Glamis and has been appraised from a single production well on extended well test.
The subsea nature of the development in andaround Balmoral and the extensive use of satellite wells makes frequent re-entries for reservoir monitoring purposes both difficult and expensive. The decision was therefore taken at an early stage to install permanent down hole pressure gauges on all satellite wells tied back to the Balmoral template.
This paper covers the details of two different gauge systems which have been installed in the area. The reliability of the systems and how the data obtained from these gauges has been used is addressed. In the light of the operational experience gained, areas for further development in pressure monitoring systems are also discussed.