bluuebunny/crossref_metadata_2025 huggingface dataset:
Oil Shale Outlook
Authors: Cameron Russell J.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

This paper was prepared for the 1974 Eastern Regional Meeting of the Society of Petroleum Engineers of AIME, to be held in Washington, D.C., Nov. 14–15, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made.

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the SPE magazines.

Oil shale is somewhat like the "old-maid" aunt. She has always been a good prospect for marriage but each suitor seems to back away at the church door. There are still a good many admirers but most think she is a bit too expensive to take to the alter right now without a fairly substantial dowry. There also is a feeling that some members of her family really don't want to see the old gal married anyhow.

So, she remains an aging maiden wistfully awaiting a lover rich enough, bold enough, and dedicated enough to overcome the obstacles fate placed in her path.

What then is the outlook for oil shale. It is pretty much the same as has been said of the outlook for Brazil. Brazil (and oil shale) have a great future, always have had a great future and always will have a great future; but the present is impossible to predict.

Look at what happened this year. On January 8, $210 million was paid for a 5,120-acre Federal oil shale lease, the highest per acre price ever paid for a petroleum prospect. Other leases in the petroleum prospect. Other leases in the same sale brought from $45 million to $117 million in high bids. Yet, in, October the Colony group (Atlantic Richfield, Ashland, Shell and Tosco) deferred their commercial shale venture on private lands after spending 10 years and more than $50 million preparing for it. Adding further to the paradox, the Colony group was high bidder on the $117 million Federal lease.

And consider this. A prestigious Federal Interagency Task Force studying the role of oil shale for Project Independence arrived at the conclusion that under an accelerated program a 1,000,000 B/D industry could be operational by 1985 without violating Federal environmental regulations or exceeding other constraints.
The Effect of Fluid Loss on Fracture Extension
Authors: Davis J.G. , Reynolds J.J. , Coffer H.F.
Published: December 2007

Field trials have shown that superior fracturing treatments may be obtained when a low fluid loss oil is employed as the sand carrier. Such a carrier now can be made very economically from lease crude oil by the use or a fluid loss controlling additive.

Experimental fracturing tests were conducted to determine the relative importance or fluid loss and viscosity in fracture extension. It was found that sand concentrations as high as 8 lb or sand per gallon could be displaced into the formation at a 4 bbl/minute pumping rate using a treated lease crude of low viscosity (12 cp) and low fluid loss. During another test 48,000 lb or sand at 4 lb/gal were displaced using the same treated crude and pumping rate. Other field tests have indicated that low fluid loss, low viscosity fluids may be successfully used where high fluid loss, high viscosity fluids are not effective. These results demonstrate the importance or fluid loss control in fracture extension.

The importance of low fluid loss is rapidly being recognized by the industry. Hundreds or wells have been fractured using lease crude with a controlled fluid loss. Fewer sand-outs are encountered and production increases tend to be more sustained. The converted oils have performed very well in formations that have been difficult to fracture in the past. Such rotations include chats and conglomerates and reservoirs with temperatures in the 200°F to 300°F range.

Both laboratory and field results have shown that crudes treated to reduce the fluid loss are fully compatible with the various gelling materials now available. The very low fluid loss gel that results from this combination is advantageous in many instances. With proper treatment design, the selection of crude oils is now almost unlimited. The development or the hydraulic fracturing process has occupied only a few years in the history of the oil industry. During this brief period, however, fracturing has become the major method for production stimulation and its application has led to the reopening of many oil fields formerly classed as depleted.
Selection of a Waterflood Pattern for the Jay-Little Escambia Creek Fields
Authors: Shirer J.A. , Ainsworth W.J. , White R.W.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

A Three-to-One Staggered Line Drive pattern was selected to initiate the pattern was selected to initiate the waterflood in the Jay-Little Escambia Creek Fields of northwest Florida and southern Alabama. This pressure maintenance program should recover in excess of 200 program should recover in excess of 200 million stock tank barrels of oil over primary operations. primary operations

Introduction

The Smackover-Norphlet Reservoir in the Jay-Little Escambia Creek Fields of northwest Florida and southern Alabama was discovered in June 1970 and is the largest oil discovery in the lower 48 states in the last two decades. Original-oil-in-place was in excess of 700 million stock tank barrels. The reservoir is located below 15,000 feet and contains a volatile, sour crude which is highly undersaturated. Production was initiated in December 1970 after sweetening facilities were installed.

A reservoir study conducted in mid-1971 indicated that there was little likelihood a natural water drive would be effective and that primary recovery would be low. Unitization and pressure maintenance were urgently needed to maintain productivity and increase ultimate oil recovery. The recovery potentials of several types of fluid injection potentials of several types of fluid injection processes were evaluated using two-dimensional processes were evaluated using two-dimensional computer simulation. Screening studies indicated that waterflooding was the most appropriate recovery process.

In early 1972 evaluations were begun to determine the optimum waterflood pattern using two-dimensional reservoir simulation and a 3:1 Staggered Line Drive was selected to initiate the waterflood. A three-dimensional reservoir model was constructed in mid-1973 to confirm the effectiveness of the 3:1 Line Drive pattern prior to converting flowing oil wells pattern prior to converting flowing oil wells to water injection service.

Results of early reservoir simulation were used to design and justify ordering long delivery waterflood equipment concurrent with field development and unitization. The effective date of the Unit was March 1, 1974, and water injection was initiated four days later on March 5, 1974.

This paper presents the methods used to select the optimum waterflood pattern to initiate the pressure maintenance program for the Jay-Little Escambia Creek Fields.
A New Approach for Enhancing Fracture Conductivity
Authors: Nguyen P.D. , Dewprashad B.T. , Weaver J.D.
Published: December 2007

A new liquid surface-modification system has been developed for coating proppant, dramatically increasing its surface friction and allowing it to interact instantaneously with surrounding particulates. High surface friction between the coated proppant grains allows them to withstand high flow rate, minimizing their flowback potential after fracture-stimulation treatments. According to field results, when this surface-modification material was used as a flowback-control agent after conventional fracturing treatments, it permitted more aggressive flowback procedures. This treatment did not impair conductivity, and in fact, increased proppant conductivity at closure stresses below 4,000 psi (27 600 kPa). Better vertical proppant distribution occurred in experiments that demonstrated how the surface modification significantly hindered proppant settling. Fines that already existed within the proppant (generated from the formation or derived from crushed proppant upon fracture closure) all adhered to the treated proppant, which inhibited them from migrating and blocking the pore throats of the proppant pack. This unique coating technology further enhanced conductivity by improving frac-gel breaker action in certain fluids. This behavior results in faster, more effective well cleanup after stimulation.

P. 109
Meeting the HSE Challenge
Authors: Mohamed Zarei B.
Published: December 2007

Petronas Carigali (PC) visions to be a multinational E&P company of choice in all areas including HSE. To advance in this effort, PC developed its Health, Safety and Environment Management System (HSEMS). PC believes in top management commitment, integration of HSE into its core business and total involvement by all including contractors. HSE which has already been accepted as line responsibilty was further strengthened by making supervisors accountable for incident reduction, regardless of company or contractor personnel. Every individual in PC promotes, practices and participates in HSE. In 1995, various HSEMS models were studied to develop a model that suits PC. During the process, stakeholders discussions were held to ensure agreement and buy-in. In 1996, PC was rated as one of the best three worldwide by E&P Forum with LTIF rate of 0.87 per million manhours and Total Recordable Cases Frequency (TRCF) rate of 1.94 per million manhours for combined company and contractor personnels. In 1997, PC bettered its LTIF and TRCF performances to 0.24 and 1.43 per million manhours respectively. The paper will discuss on the elements incorporated into PC HSEMS and the key work areas that made PC rated amongst the best.. It will also touch on PC's HSE philosophy for its international operations.
Use of Guar Gum and Synthetic Cellulose in Oilfield Stimulation Fluids
Authors: Anderson Robert W. , Barker James R.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

The use of polysaccharides to alter the rheological properties of aqueous fracturing fluids has been a common practice for many years. In certain cases the inherent properties of these natural and synthetic polymers have been negated by their sensitivity to adverse parameters present in both the base fluid and the formation. Some of these parameters have been identified as ionic strengths, transition metal concentrations, high bottom hole temperatures, and chemical redox systems.

Chemical solutions to these problems, which eliminate or minimize the detrimental effects, have been developed for field operations. Once the problem has been recognized and defined, an appropriate chemical treatment will usually make the field water usable, bypassing the necessity of finding an alternate supply. The specific treatment will depend on whether the end product is to be the polymer sol or a complex gel. Additional beneficial effects have been observed as a result of at least two of these chemical treatments. Higher base viscosities of the polymer sol and less polymer sensitivity to the ionic strength of the field polymer sensitivity to the ionic strength of the field waters have been noted in several instances. Exceptional polymer stability at higher temperatures has been obtained polymer stability at higher temperatures has been obtained with one procedure. This has effectively extended the usefulness of several polysaccharides at higher bottom hole temperatures. This paper presents a description of the various polysaccharide systems, their sensitivities, and the methods employed in countering these sensitivities.

Introduction

Since its inception, the art of hydraulic fracturing has employed an extensive array of fluids and systems. Polymers were initially developed to reduce pumping Polymers were initially developed to reduce pumping friction losses. Almost simultaneously, polymers were found useful in improving propping agent transportability and placement. The efficiency of frac fluids was later improved by additives which controlled fluid leak-off in more permeable reservoirs and in this role polymers were found to play an important part. More recently, the search for further improvement in fluid loss control, proppant transport and placement, and fracture extension proppant transport and placement, and fracture extension brought about the use of crosslinking agents to form super-viscous gels where three-dimensional networks are produced in the polymer solution. produced in the polymer solution. Howard and Fast reported properties which a frac fluid should possess.
Reservoir Management Making a Difference in Australia's First Oilfield Developed Entirely with Horizontal Wells
Authors: Allard D.N. , Sawiris R.S.
Published: December 2007

The Roller and Skate oil field is located 13 miles south-southwest of production facilities at The venard Island and 4 miles from the mainland coast of Western Australia. Roller was discovered in 1990, and Skate the year after. Production began in 1994. Roller and Skate original oil in place is approximately 77 million barrels.

Roller and Skate reservoirs are complicated by different oil/water and gas/oil contacts, 3 different gas caps within Roller and 1 within Skate, and distinct differences in oil/gas gravity and chemical composition. Net oil pay is up to 56 feet within friable sands of the Barrow Group Formation.

The paper will discuss the various development options considered, final selection, and achievements made in drilling and facilities installation.

The uncertainties overcome prior to development were; structural uncertainty due to limited well control and poor quality 3-D seismic, uncertainty of formation integrity to support barefoot horizontal completions, and uncertainty of aquifer support. In addition, effective gas-management was critical as government policy required no flaring of free gas.

This paper will highlight reservoir management practices that are being used to optimise current and future performance.

P. 165
Case History of a Marginal Oil Field Development
Authors: Soetedja V. , Suyana D. , Kontha I.N.H.
Published: December 2007

Development of a marginal oil field offers a unique set of challenges. These challenges were experienced in the development of VICO's Semberab Field, located in East Kalitnantan of Indonesia Semberab Field was originally thought to be a small oil accumulation in a mainly gas area; therefore, the facilities and development plans were conceived around a target of 5,000 BOPD. However, an aggressive development effort which included, in addition to moderate drilling and re-completions, an ongoing cost effective production optimization effort of both surface facilities and downhole completions have resulted in maintain the oil production at a level of more than 12,000 BOPD for the last five years.

This paper presents example of the ongoing development process of the Sembenrab field. Under a complex geological environment and multi-layered sandstone reservoir, the thin non-continuous oil sands encountered were initially developed without detailed planning. Rather than being driven by reservoir studies to guide the delineation program, the life of the field is extended by cost effective production optimization that in turn encourages further reservoir review.

The optimization efforts have resulted in several significant upward reserve revisions of the Semberah field. The whole field is now re-mapped with a probabilistic method in an afterupt to capture the uncertainty of the sand development. Future efforts for additional improvement will be centered on a newly instituted multi-discipline asset team.

P. 175
Propped Fracture Geometry of Three Hydraulic Fractures in Sydney Basin Coal Seams
Authors: Jeffrey R.G. , Vlahovic W. , Doyle R.P. , Wood J.H.
Published: December 2007

Three propped hydraulic fractures, placed in coal seams from vertical wells, were recently mapped as the coal mine workings passed through the site of the wells. The fractures were propped with sand and, in each case, the geometry of the propped fracture was mapped during mining as it was exposed on the roof, floor and rib (sides) of the mine openings. Permeability, stress, and structural data were collected at each site so that the fracture geometry could be assessed against these site characteristics.

The fractures at all three sites were affected by pre-existing joint and cleat fractures in the coal. Some degree of multiple subparallel fracture development occurred in each case, with the fracture at Appin being the most complex. At Appin and Munmorah the hydraulic fractures propagated along the direction of the face cleat, while at Dartbrook the fracture followed the major vertical joint direction which cuts across the face cleat direction at an angle of about 30 degrees. The fracture at Appin was contained to the seam and the fracture at Munmorah grew into the floor rock but then became horizontal. At Dartbrook, the Wynn seam is part of a thick mega seam and the hydraulic fracture grew into the over- and underlying coal, which is left unmined.

P. 191
Post-PSCs Business Development Opportunities
Authors: Yusoff Samsudin Mohamed , Kario Mohamed Wahid
Published: December 2007

Some of the early Malaysian Production Sharing Contracts (PS Cs), in particular those signed in the mid 70s have expired or are expiring. These PSCs have either been replaced or are in the process of being replaced with new arrangements. While some of the PSCs ceased operations or expired as per their natural terms, other expiring PSC's operations were modified upon mutual agreements between the PSC Contractors and PETRONAS to allow both parties to enter into more dynamic and exciting new arrangements on a long term basis.

This paper will attempt to share PETRONA'S broad experience and general approach in addressing the expiring PSCs and giving life's to these PSCs after they have expired. The paper highlights among others how PETRONAS goes about balancing between issues such as diverse commercial perspectives/forecasts and expectations; long term relationships and commitments; win-win new arrangements while enforcing national requirements.

P. 203
Implementation of "Twin Well" Technology Offshore Sarawak
Authors: Hashim S. , Runggai T. , Khalid M.Z. , Kruit W. , Short D. , Duncan B. , Pauzi N. , Haron J. , Low F.N.
Published: December 2007

Many of the existing matured fields operated by PETRONAS Carigali Sdn. Bhd. (PCSB) still contain substantial remaining reserves. However, there are often limited spare well slots or re-entry possibilities available on existing platform structures from which new wells can be drilled. Putting in new structures is costly and in many cases would render new drilling projects uneconomic. In search of new technologies to develop its matured fields, PCSB has identified the "Twin-Well" technology as a viable and relatively low risk means of further developing such fields offshore Sarawak. This paper will present the application and construction of PCSB's "Twin Well" with two separate wells (one single and one dual completion) from one conductor. The paper will highlight how this new technology was applied successfully in the Tukau field which has significantly reduced project costs and has made in-fill drilling economically more attractive. In many cases the well jackets in these fields are relatively small and normally accommodate up to four wells. In the Tukau field, no spare conductors were available and none of the existing jackets could accept more than one additional conductor. Applying "Twin Well" technology has allowed two wells to be drilled from one platform structure thus saving cost of visiting an additional jacket and having to install an additional conductor to achieve the same project objectives. The way forward will also be presented with PCSB's plans to merge the "Twin Wells" and Multilateral well technology for their future field development projects. The fact that more reserves can be developed with fewer wells from smaller platforms will allow previously uneconomic projects to now become economically robust.

This paper is well suited with the theme of this Conference "Making a difference", as a new approach is required to develop reserves under the new challenging economic conditions.

P. 293
Economic Decision-Making Practices in the U.S. Petroleum Industry
Authors: Mathur Shri B. , Carey Omer L.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

This paper explores several aspects of economic decision making in actual use by members of the petroleum industry, including cost of capital, measures of investment evaluation, required minimum rate of return, and risk-analysis methodology. Certain internal procedures utilized by the responding firms in procedures utilized by the responding firms in the application of the above mentioned measures are reported and compared.

The contents of this paper have valid implications for a variety of audiences. This study illustrates how different petroleum executives are handling economic decision making and evaluates the state-of-the-art of the economic decision-making process in the petroleum industry. The results of this study petroleum industry. The results of this study can be used by firms to evaluate and possibly improve their own practices. This paper can make its greatest contribution to smaller firms in the industry who have not yet adequately developed their economic-analysis capabilities and, hence, are searching for procedures to improve their economic decision making.

This paper is based on the responses to a four-page questionnaire that was mailed to the chief executive officers of 15 major companies in the petroleum industry; 12 companies responded.

Introduction

The opportunities for investment or capital outlays form the framework for a company's future development and are a major determinant of efficiency and competitive power. Consequently, a corporation's investment decisions have a profound effect upon its future earnings. profound effect upon its future earnings. Any business is continuously faced with the problem of making investment decisions. Even problem of making investment decisions. Even for the small business, the problem of reinvestment of earnings, expansion, or diversification is a continuing one.

Investment opportunities usually are analyzed by various segments of the organization, but the final decision is the responsibility of top management. This situation points out the need for sound programs of evaluation. Management needs an objective means of measuring and comparing the economic worth of the individual investment proposals submitted by various divisions of the organization in order to have a realistic basis for choosing among them and selecting those that will make the greatest contribution to meeting corporate goals. In addition, using objective criteria and formal guidelines for processing of capital investment proposals allow some investment decisions to be proposals allow some investment decisions to be delegated to lower levels of management, economizing on top-management time.
Strategic Planning of the NWS Offshore Expansion Activities
Authors: Goodson R.J. , di Prinzio S.
Published: December 2007

The North West Shelf Gas Project (NWSGP) comprises North Rankin A and Goodwyn A processing platforms exporting dehydrated gas and condensate through a single multiphase trunkline to an onshore processing plant on the Burrup Peninsula, N W Australia. Demand for domestic gas has been recently stimulated while the Western Pacific Rim region presents an expanding LNG market. The proximity of these markets, together with the Venture's reputation for reliable supply, and a highly successful gas exploration program, places the NWS Venture in a strong position for substantial growth in its LNG, Domgas and liquids business.

The current offshore infrastructure will require expansion to capture the future market demands (Figure 1). Woodside has initiated an Offshore Development Planning (ODP) Process designed to deliver insight and understanding into the complex technical and commercial issues which surround the continued development of the NWS. Major uncertainties facing the Venture include timing of expansion opportunities; proven and exploration reserves; and the capacity, reliability and safety of surface facilities. The ODP is a decision-focussed process that analyses major infrastructure decisions and presents understanding and insight in support of development recommendations.

This paper reviews the work associated with the current ODP program, describing the methodology and expansion strategies evaluated and how these methodologies have made a difference in the overall development strategy of the NWS.

P. 361
Probabilistic Addition of Gas Reserves Within a Major Gas Project
Authors: Carter Peter J. , Morales Enrique
Published: December 2007

The paper presents a new approach to the probabilistic addition of gas reserves within a major gas project. The correct determination of proved reserves underpins the contracted gas volumes for the project. Each individual field has a determined range of gas reserves. Whilst the proved reserves have a 90% chance of being exceeded at the field level, the arithmetic sum of the proved reserves across the project have a much higher chance (of order 99%) of being exceeded due to the independent nature of many of the risks. An appropriate technique has been developed for probabilistic addition of reserves such that the proved reserves correctly have a 90% chance of being exceeded at the project level. The approach takes into account the known dependencies between some of the assets.

The result is an auditable process that underpins the handling of subsurface dependencies within a single project to give a robust estimate of proved reserves.
Profile Control Technology of Thermal Recovery in Shengli Oilfield
Authors: Chen Shen
Published: December 2007

In the process of oil recovery by steam injection in Shanjiasi Oilfield, main problems are as following:

steam override or steam break due to gravity segregation and heterogeneity; low recovery percent of reserves after several cycles and large recovering discrepancy in vertical; active edge and bottom water as well as serious water invasion in producing wells; uneven steam injection profile and low steam sweep efficiency.

The technologies of profile control by steam foam, nitrogen and super-fine cement fly ash have been studied in this article. Filed applications in steam stimulating wells show that the technology of profile control by super-fine cement fly ash has good effect of oil-cement and water-control in Shanjiasi reservoir with active edge and bottom water. 34 well-times of applications have been carried out and the effectiveness reaches 91.7%. The effect of steam stimulation has been improved successfully. This paper describes the feasibility of adopting these conformance control technologies in Shanjiasi Oilfield. The operational parameters were accessed and optimized. A comprehensive analysis of application results was also conducted.

P. 387
Employees Perceptions of Health, Safety and the Environment in an Australian Oil and Gas Producer: A Comparison with the North Sea
Authors: Freeman Melanie L. , Smeeton Rachel , Flin Rhona , Mearns Kathryn , Rachail Gordon
Published: December 2007

The primary objectives of the 1997 Woodside Health, Safety and Environment (HSE) Perception Survey were to establish the perceptions and experiences of employees with regard to health, safety and environment, to generate a baseline series of data on the HSE culture of Woodside and to benchmark Woodside with the perceptions of employees working for six companies in the UK sector of the North Sea. The aim was to identify what HSE initiatives are perceived to be in place within the company, to determine what management is seen to be doing with regards to HSE within Woodside, and to identify what other HSE initiatives or alternatives are perceived to be needed. When benchmarked to the North Sea (n=722), employees on Woodside's offshore facilities (n=l33) had more positive attitudes and beliefs about the communication in their job, their attitudes to safety, their supervisors commitment to safety and their lack of willingness to break the rules than offshore workers in the North Sea. This is despite the fact that they perceive more work pressure in their jobs than employees in the North Sea. The HSE culture of Woodside was defined by employees in a much broader context than that of the North Sea. The Woodside employee concerns revolving around management, contractors and employee attitudes whereas the North Sea concerns revolved around management, employee attitudes and being able to speak up about safety. Overall there appeared to be a good stable safety culture within Woodside (n=682), however the health and environment cultures were not as developed within the company. Individual locations and groups of employees indicated there were specific HSE issues that needed targeting. This paper focuses on these issues and how they are being addressed within Woodside.

P. 431
The Management of Contractor HSE
Authors: Foster David L.
Published: December 2007

Contractor performance with respect to the management of HSE is a constant challenge for any company. Woodside Energy Ltd has over recent years been improving the process applied to contracted work, from prequalification to close out. This process incorporates the application of a number of tools and requirements that give a comprehensive picture of potential contractors and their ability to effectively manage HSE.

The elements that make up the process are as follows: Prequalification of potential contractorsInvitation to tender to prequalified contractorsTender evaluationContract award and pre-startContract monitoringCloseout report

Woodside focus throughout this entire process is on that of influencing the contractor. The purpose of this is to actively encourage the alignment of our HSE cultures in a climate of continuous improvement. This is an area in which a large part of our effort is applied. It is not uncommon for us to actively assist an individual contractor both pre and post award, due to the overall standard of all tenderers not being seen as high as we would wish.

The basis of our contractor evaluation is to determine how effectively they both identify and manage hazards. We look for a robust systematic approach that addresses such issues as documentation, audit, accident/hazard reporting, training identification and delivery and the concept of continuous improvement. This should all be supported by a top down demonstration of leadership and commitment from all management levels.

The evaluation process looks not only at documented responses to questionnaires, but presentations from contractors on how they intend to carry out the contract scope.

The bottom line is that good HSE management is a moral obligation as well as good business. We need contractors to assist us in achieving our business vision, so the investment of time, effort and money up front is one that has a very real potential for high returns, ensuring the safety of those who work with us, integrity of our assets and minimal environmental impact.
Optimised Float-out of Concrete Offshore Platforms Towards Increasing Construction Potential in Australia
Authors: Hill A.B. , Ronalds B.F.
Published: December 2007

With the increasing number of significant oil and gas discoveries in Western Australia and the Northern Territory, there is a predicted demand for a range of concrete gravity structures (CGSs) from the Carnarvon to the Browse Basins and the Timor Sea.

Shallow founded CGSs may be installed in soft or hard seabed conditions, with the softer conditions typically found in deeper water and requiring protruding skirt structures to penetrate the seabed to improve stability and provide scour resistance.

Such open bottom structures are floated by displacing water inside the skirted compartments with compressed air. Where construction and float-out are done in shallow water, small underkeel clearance (UKC) is likely. Wave induced motions of both the structure and the water plug inside the skirted compartments have to be accommodated to ensure that the structure does not touch the seabed and that the water plug motions do not promote the escape of air from compartments.

Pilot research into the dynamics of CGSs with small UKC has been completed and this has identified some very important parameters for inclusion in the design loop of CGSs. The research also identified parameters worthy of more thorough research and with the potential to advance the knowledge base in this area and thus provide local industry with a competitive advantage.

P. 471
Laminaria/Corallina - An Integrated Field Development Planning Approach
Authors: Shaw M.N. , Fowles J.D. , Abernethy S. , Hamp R.
Published: December 2007

The Laminaria and Corallina Fields were discovered in 1994 and 1995, within permit AC/P8 in the Timor Sea, and are currently being developed using subsea wells, manifolds, flowlines and a large Floating Production, Storage and Offloading (FPSO) vessel. Expected reserves for the combined fields ranges from 130 to 250 MMbbl and production is planned to commence in October 1999, five years after field discovery.

In order to achieve this, subsurface development studies have been conducted in parallel with facility concept and engineering design studies. Due to the large range of reserves associated with the two fields, leading edge technology and rigorous uncertainty management techniques have been used to produce a robust development plan. Seismic imaging in this area is particularly difficult and has been enhanced by using Prestack Depth Migration. Even so, structural mapping remains the largest factor contributing to reserves uncertainty.

P. 497
Application of New Generation Technology to Horizontal Well Production Logging - Examples from the North West Shelf of Australia
Authors: Carnegie A. , Roberts N. , Clyne I.
Published: December 2007

The main measurement objectives in production logging are to diagnose well production problems such as the inflow rates and entries of unwanted fluids, supply information for reservoir modeling and provide data to optimize the productivity of future and existing wells. Another important objective is to perform the measurements cost effectively.

In a horizontal well fluid density cannot be measured by the gradiomanometer. Other sensors, such as the nuclear fluid densimeter which rely on a decaying radioactive source, are inaccurate (especially in heavy oil/water regimes), environmentally hazardous and only measure within the liner. Undulations in horizontal well trajectories can cause traps of gas and water to be created at the high and low points, and large changes in fluid holdup and velocity with changes in deviation as small as one degree. Such effects can confuse or even completely invalidate the spinner for flow rates. Fluid entries, including those which are unwanted, often occur over much longer sections than those usually found in vertical wells. Consequently, the temperature effects of such entries are often insignificant, thereby decreasing the value of the thermometer. The fluid flow regimes in horizontal wells can be one or a combination of stratified, bubbly and slug flow. This often invalidates the application of models developed for vertical wells. Hence the measurement objectives in horizontal wells frequently prove difficult or impossible to achieve by using traditional tool strings and interpretation techniques. The traditional mode of conveyance of production logging tool strings in a horizontal well is by coiled tubing, which can often be very expensive and make the costs prohibitive.

The solution to the measurement problems is to employ technology which has recently been developed specifically to deal with the inadequacies of traditional sensors and interpretation techniques. The cost from rig time of employing such technology have been reduced by ensuring that all sensors are conveyed on just one tool string, thereby minimizing rig up and rig down tasks, and eliminating the necessity to pull out of the hole between logging runs. By employing tractors instead of coiled tubing the costs of conveying these sensors have been reduced further.

This paper discusses the problems mentioned above, describes a methodology for solving them, and shows how this has been done successfully in wells in the North West Shelf of Australia.

P. 511
Automated Steering Systems Applied to Complex Horizontal Well in South Italy
Authors: Calderoni A. , Oppelt J. , Ligrone A. , Trampini A. , Gauld S.
Published: December 2007

Automated directional drilling systems were amongst the key deliverables in a recently concluded joint development program between an oil company and an oilfield service provider. The two automated directional drilling systems as developed in the project have a certain degree of commonalty, however, there are also major differences in the way they work. The field experience described here was the first opportunity to run both tools together in the same well. Each of them was able to demonstrate it's specific and unique capabilities. The drilling strategy for Monte Enoc 9 required the use of a straighthole drilling system, SDD, in the upper hole sections and the rotary steering system, AutoTrak, in the 8 ½" hole size. By synergistically using the new automated tools, Monte Enoc 9 was drilled in a much more efficiently than offset wells, producing substantial time savings, a smoother hole trajectory, and less friction. The concluding 6" hole section of the well could be drilled and steered in a much easier fashion than expected because of the good conditions created in the vertical and curved hole sections. The drilling strategy as practiced in ME9OR will be further optimized to allow for even greater savings.
The Brimmond Reservoir Extending the Forties Field Into The Millennium By Maximising Profits Without Expensive Rig Upgrades
Authors: Smith L. , Perras L.
Published: December 2007

How to drill a technically ambitious horizontal well with a minimum facilities workover rig? By careful planning, good drilling practices and the help of some state of the art technology.

The drilling programme was initiated to further develop the Brimmond Field which overlies the Forties Reservoir. The Eocene reservoir was first produced through an 13ft cased hole gravel pack in a previous Palaeocene (Forties) production well. As a result of this success a development phase was instigated, commencing with an 8550ft MD horizontal appraisal and development well.

Feasibility studies had indicated that a significant rig upgrade would be required to facilitate the drilling of a horizontal well within recognised industry parameters. However, upgrading the drilling package would have delayed the project by several months and potentially made the project uneconomical. The challenge was to accelerate the programme by utilising the available minimum facility workover rig. The main limiting factors within the drilling package were: 1x 800hp mud pump, 1 shale shaker, no bulk barite or cement storage, 425 bbls of working mud pit capacity, a kelly and restricted deck space. To compound these limitations, there is no accommodation available and the drilling personnel shuttle daily from other North Sea Platforms.

A number of critical operations were identified which led to the introduction of ‘new technology’ – premixed cement, leading edge LWD tools and hole clean up techniques. After assessing all the challenges, the team embarked on the most technically ambitious well to date for the Forties Field.
Feasibility of Oil Recovery by Chemical Flooding through Horizontal Wells
Authors: El-Abbas A. M. , El-Sallaly M. E. , Sayyouh M. H. , El-Batanony M. H. , Darwich T. M. , Desouky S. M.
Published: December 2007

A laboratory and economic study on Badri crude oil production by polymer, surfactant and surfactant/polymer flooding from a horizontal well in a scaled five-spot sandpacked model was conducted. Crude oil from Gupco* Badri Field was used in the displacement tests. The grain size distributions of the used sand are similar to those of the Badri formation. Surfactant and polymer slug concentrations were 1.0% by weight and 500 PPM, respectively. Physical properties of the surfactant and polymer solutions were experimentally determined to select those most suited for the displacement runs. The suitability of the enhanced oil recovery predictive models**, developed by the department of energy (U.S.A), to predict the experimental data and assess the feasibility of oil recovery by chemical flooding was investigated. Results show that the maximum oil recovery is obtained from the sandpack model by polymer flooding with a slug size equal to 30% of the pore volume. A good agreement exists between the experimental data and values calculated from the software. The economic study revealed the feasibility of oil recovery from Badri oil field by polymer flooding through a horizontal well configuration.
The Model Coupling Fluid Flow in Reservoir with Flow in Horizontal Wellbore
Authors: Liu Xiangping , Jiang Zhixiang
Published: December 2007

In this paper, the 3D steady-state pressure distributions are derived of oil flow in a reservoir due to a horizontal well for several kinds of reservoirs, And based on the principle of conservation of matter and momentum theorem a new formula is also derived to calculate pressure drop along the horizontal wellbore. This formula considers the effect of influx into the horizontal wellbore from the reservoir on pressure drop in the wellbore. A mathematical model is presented to couple fluid flow in the reservoir with the flow in the horizontal wellbore. Example calculations showed that prediction results using the proposed model are in good agreement with test or experimental data. The pressure drop in wellbore has influence on performance of well. Because of the pressure loss in horizontal wellbore IPR curve for single-phase liquid flow in wellbore is not straight line, and production rate does not increase with increasing wellbore length when the length exceeds a certain value. The productivity indices per unit length for all segments along horizontal wellbore are not the same.
Past & Future Contribution of Rock Mechanics Research to Petroleum Engineering
Authors: Kenter C. J. , Currie P. K.
Published: December 2007

A brief historical review is given of the benefits of research and development in Rock Mechanics as applied within Petroleum Engineering. It is concluded that the major challenge for the coming decade is the acquisition of reliable data for input to the existing theoretical models. Successful application in the field of Rock Mechanics research depends not only on having an identified business need and the right technology to fulfill that need, but also requires a committment to dialogue between the researchers and the field.
Experimental and Numerical Upscaling of Two-Phase Flow in Homogeneous and Heterogeneous Porous Media
Authors: Abtahi M. , Torsaeter O.
Published: December 2007

The main purpose of this paper is to present some results of visual two-dimensional model experiments performed to study upscaling methods in both homogeneous and heterogeneous porous media. Well-defined heterogeneous models and fluid systems have been systematically varied to capture the effects of heterogeneity on flow behaviour in small-scale (10x40 cm2) and large-grid block (1.6x6.4 m2) models by three steps.

Heterogeneous and layered models are fabricated using packing of glass beads with four different sizes. Each one of the homogeneous models is packed with one type of glass beads. In order to simulate the immisicible displacement process, a light oil was injected into the models at three different constant rates. The interfacial tensions (IFT) of the system were reduced from 37 to 9.2 and 2.2 mN/m using two types of surfactants. The changes in flow rates and IFT are performed to reproduce the situations that match the capillary and/or viscous-dominated regimes. Totally 24 successful experiments were performed.

The capillary-dominated model represents the small-scale (a typical core laboratory condition) and the viscous- dominated model represents the large block (a typical grid size) where the capillary force is neglected. A three-step scaling-up process is used to capture the effect of the small- scale heterogeneities to medium-scale and finally to the large- grid which can be used in field reservoir simulation. The scaling-up from the small- to medium-scale matches perfectly the experimental data (pressure difference over the model and water cut) for homogeneous, layered and heterogeneous models. The final step, the scaling-up from the medium- to large-grid did not match the experimental results well. The results show that setting the relative permeabilities obtained at low 1FF directly to the large-grid block gives better results than scaling-up of the small-scale (rock curve) using three-step pseudo functions. The low IFT system relative permeability curves can be set directly to the large-grid block provided that corresponding dimensionless number values are equal.

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Critical Requirements for Successful Fluid Engineering in HPHT Wells: Modeling Tools, Design Procedures & Bottom Hole Pressure Management in the Field
Authors: Gao Erhu , Estensen Odin , MacDonald Colin , Castle Stephen
Published: December 2007

This paper presents developments in the management of drilling fluids for use in high-pressure, high-temperature (HPHT) wells, especially a process that includes both a methodology for the management of bottom hole mud pressure and the use of modeling software that enables it, The developments have contributed to the success of four HPHT wells in the UKCS Central Graben. This paper discusses three essential elements for successful fluid engineering during HPHT drilling operations.–an accurate hydraulics program coupled with a temperature simulator–procedures for design and planning–bottom-hole pressure management in the field

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Hole Cleaning During Deviated Drilling - The Effects of Pump Rate and Rheology
Authors: Saasen A.
Published: December 2007

In the present paper it is shown that the frictional pressure loss in the annulus is the major contributing part to hole cleaning in deviated wells. A sufficiently large annular frictional pressure loss is required to obtain proper hole cleaning regardless of the drilling fluid design. It is shown that cuttings bed consolidation is the next item to be addressed. A very high frictional pressure loss may be necessary to remove cuttings from the bed if the bed is well consolidated. It is also illustrated how important it is to design a drilling fluid regarding hole cleaning performance at the correct annular frictional pressure loss.

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