bluuebunny/crossref_metadata_2025 huggingface dataset:
Prop-Packed Fractures - A Reality On Which Productivity Increase Can Be Predicted
Authors: Wendorff C.L. , Alderman E.N.
Published: December 2007

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

Production increases resulting from fracture treatments should be based on the conductivity and location of the propping agent - not on the area created by the frac fluid. Model studies show that in conventional fracture treatments propping agents settle to the bottom of a fracture forming a packed pile of prop. The location and dimensions of the pack are dependent on the physical properties of the prop, fluid and physical properties of the prop, fluid and formation, the geometry, volume and length of the fracture, and the pump rate.

This paper presents a mathematical procedure for predicting the location and procedure for predicting the location and dimensions of the prop pack in a vertical linear fracture. A computer program has been prepared and is currently being used in designing fracture treatments.

Introduction

Studies we have made in models of vertical and horizontal fractures show that in conventional frac treatments props end up in a multilayer packs. We observed this in models where no leak-off occurred as well as in a vertical model with leak-off through one face. Other authors have demonstrated the same phenomena. To the best of our knowledge no one has published model studies which demonstrate that monolayer or partial monolayers are obtained in conventional frac treatments, i.e., where low viscosity gelled oil or water is used as the fracturing fluid.

With few exceptions field treatments designed on the basis of monolayer or partial monolayer concepts have not responded any better than conventionally designed treatments. Lab studies, on the other hand, show fracture conductivities of partial monolayers are much greater than conductivities of a pack. We believe this inconsistency is evidence a pack occurred.

Our model studies supplied a considerable amount of equilibrium velocity data. Earlier work had described the areal extent of a prop pack where no leak-off occurred. Our goal was pack where no leak-off occurred. Our goal was to describe both the areal extent and location of the prop pack under conditions where leak-off occurred.
A New Approach to Preventing Lost Circulation While Drilling
Authors: Fuh Giin-Fa , Morita Nobuo , Boyd P. A. , McGoffin S. J.
Published: December 2007

This paper presents a new concept, theoretical formulations, and field test results of the loss prevention material (LPM*) developed for use in many possible applications such as high-angle and horizontal well drilling, drilling through severely depleted formations (to optimize casing requirements), drilling through highly tectonically active areas (i.e., regions of over-thrust faults and salt dome structures) where the in situ rock stresses are high and directionally unequal. Both open-hole microfractures and 5000-ft open-hole leak off tests using LPM were successfully conducted in our wells in Newkirk, Oklahoma, and Ventura, California. LPM is a specially selected (material strength and specific gravity) and narrowly sized granular material which, after being fully mixed in oil or water based mud at an optimum concentration, can provide good protection to formations against lost circulation while drilling.

Higher formation fracture resistance resulting from the use of LPM in drilling fluids can reduce or prevent the occurrence of lost circulation while drilling. This paper will show that a remarkable increase of 8.0 ppg in borehole breakdown pressure was achieved in one of our tests in the Newkirk well. An increase of fracture propagation pressure in the range of 3.0 to 6.0 ppg was recorded in the field tests. These results are in general agreement with our laboratory findings also discussed in this paper.
New Standard Set for South Texas Drilling Performance
Authors: Simon J. M.
Published: December 2007

This paper describes the drilling performance, techniques and equipment used to attain a 50 percent reduction in rig days during Shell Western E&P Inc.’s (SWEPI) 13 well redevelopment drilling program. One of the wells drilled during this program reached a depth of 14,450 ft in less than 17 days (This is believed to be the fastest onshore geopressured well ever drilled to this depth). Additionally, two world record bit runs for cumulative footage with an 8.5-in. bit were attained.

In 1989 a redevelopment drilling program began on the A. A. McAllen "B" lease located in Hidalgo Co., TX. These wells were land locations drilled to an average depth of 14,500 ft with typical bottom pressures of 13,550 lb/in2 (psi) and bottom hole temperatures of 350°F. These wells were drilled as infield wells and several wells experienced pressure depletion related problems during the drilling process. Numerous improvements in all aspects of the drilling operation were made during the drilling of these wells. The 14 previous wells drilled on this lease averaged 66 days from spud to rig release. The 13 redevelopment wells averaged only 33 days (50 percent average improvement).

This paper will review the drilling history on the lease and then discuss the various factors and techniques which have led to this dramatic improvement in drilling performance. Also included in this paper are the results seen while using different mud systems to drill these wells.
Case Histories of MWD as Wireline Replacement: An Evolution of Formation Evaluation Philosophy
Authors: Cantrell L. A. , Paxson K. B. , Keyser B. L. , Ball Scott
Published: December 2007

Since its introduction in the late 1970's, measurement while drilling (MWD) technology has evolved from an auxiliary directional drilling service to a fully integrated logging package for quantitative reservoir characterization. Many major and independent oil companies are now re-evaluating traditional formation evaluation methods, commonly utilizing MWD technology as a replacement for routine wireline logging services.

Recent MWD logging case histories are presented from the Texaco operated Kilauea (Green Canyon Blocks 6 and 50) and Tick (Garden Banks Block 189) Projects from the Gulf of Mexico Flexure Trend for the purpose of evaluating their utility for quantitative reservoir characterization. Single and multiple depth of investigation resistivity, formation density, neutron porosity, and dual gamma ray MWD responses are compared and contrasted with their correlative wireline counterparts. Petrophysical evaluations are corroborated by conventional core data, borehole images, sidewall core, and production data. MWD "near/far" neutron count rate overlays were employed for qualitative evaluation of hydrocarbon type. Measurements after drilling (MAD) were recorded for indication of relative permeability and detection of moveable hydrocarbons.

Comparative evaluations proved conclusively that MWD could be used as a substitute for correlative wireline logging suites where borehole size was not a limiting factor. Texaco's recent experience with MWD has evolved from that of a "last resort" application toward that of a primary logging suite for formation evaluation. This philosophical change in utilizing MWD has resulted in significant savings in rig time and associated costs. Additionally, difficult, well plans were drilled and evaluated with confidence; geopressure was safely monitored; and tops of conventionally cored intervals were selected. Geological interpretations and quality operational decisions were made before the wells reached total depth, creating a more efficient business process.
Cenezoic Uplift and Caprock Seal in the Barents Sea: Fracture Modelling and Seal Risk Evaluation
Authors: Makurat Arel , Torudbakken Bjørn , Monsen Karstein , Rawlings Colin
Published: December 2007

Among the possible reasons for leakage from reservoirs in the Barents Sea are spill due to tilting, expulsion caused by gas expansion and cap rock failure. All mechanisms have been related to the pronounced Cenozoic uplift of the Barents Shelf.

This paper focusses on how the uplift has influenced the cap rock seal. The simulations presented comprised Late Jurassic rifting at shallow burial, post-rifting sedimentation followed by two phases of Tertiary uplift/erosion with subsequent compression and extension at different depths of burial. The two main results from these simulations are: a) that cap rock failure may occur due to the build up of deviatoric stresses during uplift, and b) that minimal strain is required to initiate fracturing during extensional or compressional tectonics.

By combining the map of total erosion with the results of the fracture modelling study presented, uplift could be identified as a critical factor in structurally high areas. Fracture initiation in cap rocks is less likely in basinal areas. As a result exploration can be concentrated on the most promising areas.
Reservoir Characterization With Probability Field Simulation
Authors: Srivastava R. M.
Published: December 2007

Probability field simulation is a general methodology for producing equiprobable models of rock and fluid properties that honor the available data, and that honor the distribution and spatial continuity of the property being modelled. This paper introduces the basic idea behind probability field simulation, documents the practical application of the method through case studies, and discusses its strengths and weaknesses.
Proppant Convection and Encapsulation in Hydraulic Fracturing; Practical Implications of Computer and Laboratory Simulations
Authors: Cleary M. P. , Fonseca Amaury
Published: December 2007

Our work shows that the most important single consideration in hydraulic fracturing should be downward convection of heavier proppant-laden stages in vertically uncontained fractures. This mechanism has been absent in simulators and design approaches used by the industry: some industry personnel still refuse to accept the negative implications of extensive vertical fracture growth and, even when accepted, the convection process cannot be handled by current industry models. The efforts reported here are aimed at quantifying the phenomenology involved and incorporating the results into a practical simulator, developed for the Gas Research Institute (GEI), which also uniquely represents the physics of 3-D rock deformation and fluid flow. Two major conclusions should greatly affect field practice: Convective downward motion, even in simple fluid treatments, dominates over particle settling.Encapsulation of viscous fluids by low-viscosity fluids available (e.g. gas/water) greatly accelerates the process.

Our quantification covers a range of fluids and fracture opening behavior, for both laboratory conditions (as verification) and for typical field job schedules. Super-computer simulations were required for detailed analysis of the processes involved, but the experience gained is being down-loaded to a simpler practical fracture analysis system, which was adapted to run on portable (PC) machines, for on-site implementation and re-design of treatments, based on real-time analysis of data collected. Such simulations show that convection should be the dominant mechanism in fracturing of most reservoirs and this leads to a series of practical recommendations which are greatly at odds with "conventional wisdom" in the industry, with resulting major implications for the execution, cost-savings and benefits of fracturing.
Modeling of Gas Rates Through 1-in., Nitrogen-Charged Gas-Lift Valves
Authors: Acuña H. G. , Schmidt Z. X. , Doty D. R.
Published: December 2007

The main objectives of this study were to test three one-inch nitrogen-charged gas-lift valves from different manufacturers and to develop or modify existing procedures to accurately predict valve flow performance. During the testing program more than 360 air flow performance curves were collected under simulated downhole conditions. Injection pressures ranged from 400 psig to 1800 psig and sampled data included orifice, throttling and transition flow regimes. Various techniques to calculate the minimum injection pressure to sustain orifice flow based on the dynamic tubing sensitivity, were also investigated.

Testing demonstrated that different valves experience different flow rates, even when the port sizes installed in the gas-lift valves are the same. Our study showed that one-inch valves have lower flow capacities than 1-1/2-inch valves. Various sensitivity tests were performed to identify which valve components obstruct the flow in the smaller valves. Testing procedures to fully describe the flow characteristics of gas-lift valves are also presented. These procedures were proposed to be adopted as API Recommended Practice 11V2 for gas-lift valve testing methods.
Fracturing Unconsolidated Sand Formations Offshore Gulf of Mexico
Authors: Monus F. L. , Broussard F. W. , Ayoub J. A. , Norman W. D.
Published: December 2007

This paper presents case histories for two offshore Gulf Coast wells completed with hydraulic fracture stimulation treatments followed by gravel pack installation. This completion technology is relatively new to the Gulf Coast area and is being employed to address the unique sand conditions encountered with unconsolidated sandstone reservoirs.

Successfully fracturing soft sandstone formations poses different challenges than fracturing hard-rock reservoirs. The tip screenout design technique is used for fracture design to ensure that the fracture width and proppant concentrations are adequate to efficiently connect the reservoir to the wellbore. Downhole pressure measurements and multiple-tracer isotope tagging of fracturing fluids and slurry are used both for on-site design aids and post-job evaluation. The case histories presented demonstrate that hydraulic fracturing of soft sandstones can provide effective stimulation when properly executed.
Field and Laboratory Experience in Closed Fracture Acidizing the Lisburne Field, Prudhoe Bay, Alaska
Authors: Bartko K. M. , Conway M. W. , Krawietz T. E. , Marquez R. B. , Oba R. G. M.
Published: December 2007

This paper describes the laboratory and field work performed to understand and improve the stimulation of the fractured carbonate formation producing in the Lisburne Field, Prudhoe Bay, Alaska. Within the producing formations, the lower Wahoo intervals are low permeability, fractured dolomitic zones that produce poorly when compared to the higher permeability upper intervals. Past attempts to stimulate these intervals have included propped fracture techniques and standard acid fracture techniques. A laboratory study evaluated the effects that various acid systems have on Wahoo rock properties, the degree of permeability enhancement, and stability of acid fracture conductivity. Various acid fracturing techniques were also investigated to determine which technique and acid system created long-term fracture conductivity. The laboratory study indicated the optimal treatment would be obtained by using emulsified acid in a fracture acidizing treatment followed by a closed fracture acidizing stage using emulsified acid. The unique combination of this particular acidizing technique and acid system has increased productivity in the Lisburne Field.

Complete documentation of the field work optimization program is included in this paper. Pressure buildup (PBU) analysis has indicated fracture half lengths are from 25–100 feet long and production spinner surveys have determined that lower intervals are contributing to production. To date, over 40 new and old wells have been stimulated using emulsified acid with the closed fracture acidizing technique. Significant increases in production and reserves are currently being seen from this program.
Geologic and Reservoir Mechanisms Controlling Gas Recovery From the Antrim Shale
Authors: Kuuskraa V. A. , Wicks D. E. , Thurber J. L.
Published: December 2007

The Antrim Shale is one of the most active natural gas plays in the U.S., accounting for more than 10% of all gas well completions in 1991. Yet, geologic and production mechanisms of this large, unconventional resource remain poorly understood. Complex reservoir phenomena controlling production include two-phase flow, gas desorption, and fracture permeability. Current operational practice, which relies on gas-assist to lift formation water and reduce bottom-hole pressure, may not optimize well productivity, currently averaging about 85 Mcfd in the basin.

The reservoir processes controlling gas production in the Antrim Shale involve a combination of characteristics typical of three types of unconventional reservoirs: coalbed methane, fractured shales, and tight gas sands. Adsorption, as the primary gas storage mechanism, requires lower downhole operating pressures to achieve gas production. Fracturing of the Antrim, as the primary process controlling natural permeability, requires improved knowledge of fracture density, dimensions, and geometry. Free gas stored in micropores within the shale matrix, similar to tight gas sands, requires an understanding of water and gas saturation. This makes the Antrim Shale a "triple-porosity" system which requires the development of new reservoir modeling tools to predict well productivity from test and early time production data.

A simulation sensitivity study was conducted on the Antrim Shale using the COMETPC-3D reservoir simulator. This study varied fracture spacing, porosity, sorption time, matrix compressibility and other parameters to identify the most sensitive variables.

Downhole pumps have recently been introduced to more effectively dewater Antrim wells. These pumps can reduce flowing bottom-hole pressure to 50 psi, sufficient to achieve favorable relative permeability and to improve gas desorption. A GRI-funded field project at NOMECO's Bagley East Project which converted a gas-assist Antrim well to downhole mechanical pumping led to a 116% increase in gas production, demonstrating the importance of dewatering and BHP reduction in optimizing Antrim gas production.
Cotton Valley Production Enhancement Team Points Way to Full Gas Production Potential
Authors: Hunter J. L. , Leonard R. S. , Andrus D. G. , Tschirhart L. R. , Daigle J. A.
Published: December 2007

Description of the paper: This paper describes the origin of the Cotton Valley Production Enhancement Team (CVPET), discusses the approach the team has taken to enhance gas production in the east Texas area of the Cotton Valley formation, and presents findings made up to the time of this writing. An exhaustive study of 275 Cotton Valley (CV) wells, operated by 19 companies in east Texas, is in progress; study methods devised on a 17-well pilot test formed the basis for the study methods used on the 275-well sample.

The CVPET was formed after preliminary studies showed that two of every three CV wells were producing below the average rate for the field. Reasons for the vast production swings among wells were (and are) being sought. Companies drilling and producing from the CV formation were invited to join in a cooperative effort to assemble and analyze data that the organizers hoped would lead to gas production at the full potential of each well.

Results, observations, and conclusions: A massive data base on CV completions has been developed. This data base has allowed development of means of normalizing well completion information, thus allowing a fair comparison of completion techniques. An accurate and easy to use technique to compare production potential of CV wells has been developed and tested. Fracture design optimization and maximization of operating company return on investment have been more nearly achieved.

Applications: Techniques described may be used to analyze completion options in any operating area of the world. Specifically, CV well completion designs may be enhanced after analysis using techniques described and discussed. The paper shows the value of cooperative studies and information exchange among operators and service companies.

Technical Contributions
Simulation of a North Sea Chalk Reservoir With Dynamic Rock and Natural Fracture Properties: Case Study of the Valhall Field
Authors: Powley K. D. , Peng C. P. , Ali Nazir
Published: December 2007

Many of the reservoir uncertainties in the Valhall Held are tied to the dynamic behaviour of the reservoir rock. The high porosity chalk is relatively weak and will experience plastic deformation with reservoir depletion. This results in significant rock compaction, matrix and fracture permeability decline, and shrinkage of the field’s dual porosity area with declining reservoir pressure. Rock compressibility ranges up to 120 E-6/psi, current fracture permeabilities are less than 10 percent of initial, and the dual porosity area is currently 20 percent of original areal extent.

This paper outlines the overall approach used to develop a reasonable predictive tool to guide reservoir management decisions. Key elements include a sophisticated mathematical model, prudent data collection, in-depth evaluation of all available information, and a history match approach that requires direct use of actual data. Evaluation and representation of the reservoir’s dynamic rock and natural fracture properties are described in-depth.
The Gullfaks Field Development: Challenges and Perspectives
Authors: Tollefsen Svein , Graue Eirik , Svinddal Stein
Published: December 2007

The Gullfaks Field is located in the Norwegian Sector of the North Sea, block 34/10, and currently has the capability of producing more than 70,000 Sm3/d of oil (440,000 stb/d) from three CBS platforms. The reservoir sands comprise shallow marine to fluvial sediments of the Cook Formation, Statfjord Formation and Brent Group, ranging in age from Early to Middle Jurassic. Water injection is the major drive mechanism for maintaining reservoir pressure above bubble point.

Development wells have confirmed a complicated structural picture with numerous faults beyond seismic resolution, causing major impacts on predicting field reserves and flow patterns. Reverse faulting in an area of predominantly normal faulting further emphasises the structural complexity.

Complex geology along with field performance after water breakthrough resulted in several changes in the initial development strategy. Production from the highly productive Tarbert and Statfjord sands was accelerated in order to compensate for the loss of production from the Lower Brent sands caused by sand production after water breakthrough. Development of complex Ness and low productivity Cook sands have recently commenced.

Gravel packing, implemented in the Upper Brent field development, provided sand control and increased production rates. Various types of chemical sand control are currently being evaluated and tested in the field. Lowering pressure in gravel packed wellbore region below bubble point may increase the production rates even further.

Following advances in drilling technology, highly deviated/horizontal wells improve recovery and accelerate field development by combining production from several reservoirs in one single well. A test programme for surfactant and WAG flooding has been implemented on the field. Other EOR methods, such as gel and polymer flooding, are currently being investigated for potential use.
Gas/Oil Gravity Drainage: Laboratory Study of Oil Reimbibition and Streaming Between Stacked Matrix Blocks
Authors: Vidal Jerôme
Published: December 2007

In naturally fractured reservoirs, the gas-oil gravity drainage of stacked blocks may result in an oil flow through the matrix blocks or within the fractures network. This laboratory study outlines factors affecting the distribution of oil fluxes in the fractures and in the matrix blocks.

Gravity drainage and spontaneous reimbibition tests were carried out on single blocks and on stacked blocks with capillary continuity. Experiments were performed on blocks with sealed (ID case) and open (3D case) lateral interfaces. The oil can be expelled out of the matrix and then either flows in the fracture or is reimbibed in the lower blocks. Both streaming and drainage oil rates were separately measured for various flow rates on the upper block of the stack.

Causes of the flow out of the matrix and reimbibition are discussed. They are mainly due to heterogeneity of the petrophysical properties along the stack: permeability, capillary pressures for drainage and imbibition, saturation history, fractures capillarity. The spontaneous flow rate of oil through a matrix block is not only controlled by the block permeability. It also depends on boundary conditions imposed by the upper and lower blocks due to the capillary continuity through the fractures. All the oil flowing in the fractures is not systematically reimbibed in the lower matrix blocks, as previously thought. This is essential for the production forecast of fractured reservoirs.

Numerical simulations were conducted using a finely gridded single porosity model. Comparisons with experimental results have outlined the sensitivity on some basic parameters, i.e. the capillary pressure curves and their hysteresis.
Oil Prospects In Argentina A Country With A Rapidly Growing Economy
Authors: Buckwalter John F.
Published: December 2007

Introduction

During the years 1964 and 1965, American oil companies in Argentina were in the process of negotiating settlements with the Argentine government to recover their investments preparatory to leaving that country. This turn around of events resulted from President Arturo Illia's decision to carry through his campaign President Arturo Illia's decision to carry through his campaign promises "to eliminate the foreign oil companies and return the promises "to eliminate the foreign oil companies and return the oil wealth of Argentina to the Argentine people." This act would eliminate the oil companies who came to Argentina during 1957 and 1958 at the invitation of President Frondizi who immediately preceded Illia in office. In Argentina, the government owned and preceded Illia in office. In Argentina, the government owned and operated oil company is Yacimientos Petroliferos Fiscales or YPF. It was through YPF that the government made settlements to these oil companies.

First Contract for Ryder Scott

In June of 1964, Ryder Scott Company Petroleum Engineers received information about YPF's desire to obtain technical assistance to conduct waterflooding in several of its oil fields. This information was received in the form of a request from a manufacturer's representative in Buenos Aires who wanted to supply assistance to Ryder Scott to qualify as a bidder and then enter into competitive bidding to secure a service contract from YPF.

In view of the mass exodus of oil people from Argentina, this was a difficult decision for Ryder Scott. Most bankers said "no, don't go to Argentina." Oil companies and service companies said they were disappointed with the turn of events in Argentina.
Utilization of Chemical-Enhanced Oil Recovery Technology to Remove Hazardous Oily Waste from Alluvium
Authors: Pitts M. J. , Wyatt Kon , Sale T. C , Piontek K. R.
Published: December 2007

Chemical enhanced oil recovery technology can be used to remove oily contaminants from soil. Laboratory studies demonstrated that a variety of alkali plus surfactant combinations can be used with polymer to reduce waterflood residual oil saturation. In these studies, the oil saturation of laboratory corefloods was reduced to 0.01 pore volume. Waterflood plus chemical flood wood-treating oil recovery from corefloods was 98 percent of the initial oil saturation.

In addition, a field demonstration program is discussed in which alkaline-surfactant-polymer solutions were used to remove wood-treating oil from alluvium. In the first stage, performed in 1988, waterflood plus chemical flood oil recovery from the alluvium was 94 percent of the original wood-treating oil in place. The second pilot was performed a year later with a slightly different chemical injection scheme. Water-flood and chemical flood oil recovery from the alluvium was 96 percent of the original wood-treating oil in place. While the results indicate a large reduction in contaminant mass, numerous site specific issues related to the feasibility of full-scale application remain.
The Effect of Pressure and Temperature on Pore Volume Compressibility
Authors: Von Gonten W.D. , Choudhary B.K.
Published: December 2007

Pore volume compressibility is one of the physical properties of a reservoir that must be specified in many reservoir engineering calculations. In this research, the effect of compacting pressure, temperature and porosity on compressibility was investigated.

A total of nine different cores were tested, eight were sandstone and one was limestone. Core samples were placed in copper jackets and subjected to compacting pressure up to 15,000 PSI. Runs were made pressure up to 15,000 PSI. Runs were made at room temperature and at 400 degrees F.

Very late has been published concerning the effect of temperature on the pore volume compressibility of reservoir rock. This work shows that the pore volume compressibility increases with increasing temperature for the same pressure. In most cases, about a twenty percent increase in compressibility was noted at 400 degrees F. as compared to room temperature.

The compressibility was found to be a continuous function of compacting pressure. The compressibility at 14,000 PSI compacting pressure was only about one-third of the pressure was only about one-third of the compressibility at 1,000 PSI.

From the research that has been performed, no method has been found for performed, no method has been found for accurately predicting pore volume compressibility. Therefore, when accurate compressibility data for a reservoir are needed, laboratory measurements should be made on core samples from the specific formation simulating reservoir temperature and compacting pressure.

Introduction

In the past few years, much emphasis has been placed on sophisticated reservoir engineering such as mathematical reservoir models and transient reservoir flow tests. One of the physical properties that must be specified in this type of work is the pore volume compressibility of the reservoir rock.
The Comparison of Petroleum Contractual Systems in Asia Pacific
Authors: Partowidagdo Widjadono
Published: December 2007

The earnings from oil and gas sales are a very important source of income for some countries in Asia Pasific Region. The hydrocarbons are also important source of energy for almost all of the countries in the region.

Most governments in this region invite foreign companies to their countries to supply the risk capital for petroleum exploration and development in exchange for a direct share in the potential profit.

In this study, a comparison of different hydrocarbon fiscal systems and profitability in Asia Pasific Region is presented.
Reusable Platform Concepts
Authors: Gudmestad O. T. , Sparby B. K. , Stead B. L.
Published: December 2007

There is an increasing need to reduce costs of offshore production facilities in order to make development of offshore fields profitable. For small fields with short production time there is in particular a need to investigate ways to reduce costs. The idea of platform reuse is for such fields particularly attractive. This paper will review reusable platform concepts and will discuss their range of application. Particular emphasis will be placed on technical limitations. Traditional concepts as jackups and floating production facilities will be discussed but major attention will be given to newly developed ideas for reuse of steel jackets and concrete structures. It will be shown how the operator for several fields can obtain considerable savings by applying such reusable platform concepts.
Cost-Effective Gas Control: A Case Study of Surfactant Cement
Authors: Hibbeler J. C. , DiLullo Gino , Thay Michael
Published: December 2007

Gas migration during primary cementing has been the subject of numerous studies and is well documented in referenced literature. Methodologies to predict gas flow potential have been devised and various systems have been offered to prevent the phenomenon. However, high cost associated with these systems has made them unattractive for many well candidates having marginal potential for gas flow. This prompts the possibly unsafe choice between merit and economics. With this in mind, a cost effective slurry was developed, incorporating surfactant to prevent annular gas flow.

Surfactant cement is a conventional slurry to which a foam generating surfactant is added. Originally developed in 1973 by the Institute Francais du Petrol, surfactant cement has been utilized in several applications worldwide. Surfactant immobilizes formation gas by converting it to a highly viscous low mobility foam. The addition of surfactant also lowers a slurry's surface tension, thereby preventing bubbles from coalescing and becoming mobile. The combination of these two mechanisms combined with thoughtful slurry design will greatly reduce the risk of annular gas flow after cementing.

The purpose of this paper is to illustrate, via case study, the cost effectiveness of surfactant cement when used for gas control purposes. A brief overview of annular gas flow causes, conventional aspects of gas control slurry design, and description of surfactant gas control mechanisms are also presented.
Towards Common Technical Standards
Authors: Rahmat Hussein , Suardi A. R.
Published: December 2007

In 1989, PETRONAS launched its Total Quality Management (TQM) programme. In the same year the decision was taken by the PETRONAS Management to introduce common technical standards groupwide. These standards apply to the design, construction, operation and maintenance of all PETRONAS installations in the upstream, downstream and petrochemical sectors. The introduction of common company standards is seen as part of an overall technical management system, which is an integral part of Total Quality Management.

The Engineering and Safety Unit in the PETRONAS Central Office in Kuala Lumpur has been charged with the task of putting in place a set of technical standards throughout PETRONAS and its operating units.

Several options have been evaluated. The strategy which was finally selected involved the acquisition of standards from major oil companies (rather than re-inventing the wheel and creating new standards) and converting these standards into sound PETRONAS Technical Standards (PTS).

The PTS are based on, and need to be used with, recognised international, national and industry standards.

The PTS are complementary to relevant external standards such as ISO, IEC, API, MS and reflect PETRONAS Management Policies regarding Safety, Health, Environment and Technical Integrity.

Several of the frequently used national and industry standards which are accepted worldwide in the oil and gas industry are now being proposed to become, after minor adaptation, international standards.

The PTS therefore, will increasingly be based on international standards.

The Acquisition of standards from three companies has been completed and the Implementation Programme has been under way for about one year. Several PETRONAS Operating Units (OPUs) are already using the PTS, others are in the process of gradually introducing them. Steering and Working Committees have been set up while Custodians and OPU Focal Points have been identified. Input and feedback from the OPUs in the field is vital to achieve Standards which are fully acceptable.

Special tools such as the CD-Rom system. Standards Manuals and Document Control Systems have been developed and are being implemented.

PETRONAS has set 1997 as target to complete the conversion and adaptation process for the PTS.
Meeting the Challenge of Extremely Corrosive Service: A Primer on Clad Oilfield Equipment
Authors: Pendley M. R.
Published: December 2007

Extremely corrosive environments, such asthose often encountered in deep, hot, sour oil and gas wells, are usually characterized by the presence of hydrogen sulfide (H2S), carbon dioxide (C02), Chlorides, and other corrosive species coupled with high temperatures (>400°F/204°C) and high pressures (up to 20,000 psi/138 MPa). Most low alloy and stainless steel materials are not suitable for such environments.

Extremely corrosive Service conditions dictate the use of a corrosion-resistant alloy (CRA) in areas which are exposed to the hostile environment. However, it is often cost-prohibitive to make an entire component out of CRA material. An alternative strategy is to use a low alloy steel for the bulk of the component and clad critical surfaces with a corrosion-resistant material. Clad equipment can provide excellent corrosion resistance in hostile environments atafraction of the cost of 100% CRA components.

This paper will detail the problems posed by extremely corrosive environments and discuss how clad equipment provides a cost-effective solution.
The Changing Role of Reservoir Engineering in the Airlie Project
Authors: Della Lou , Anderson B. D.
Published: December 2007

This paper discusses the changing role of reservoir engineering in the various stages of a marginal development offshore Western Australia known as the Airlie Project. The project, which comprises three thin oil column fields, South Pepper, North Herald and Chervil, was made possible through an innovative approach to development. This included the pioneering of horizontal well technology in Australia, the use of a jackup drilling rig as a production platform and the application of monopod and minimal structure concepts for wellhead Support. Specifically the paper addresses the use of horizontal and high angle slant production wells in marginally economic thin oil columns, and discusses the successes, the failures and the general philosophy applied to the development. The results of several numerical reservoir Simulation studies are used to illustrate these aspects.

The evolution of the role of reservoir engineering is followed from the feasibility stage through the initial development, to the mature stage including two infill drilling programs in South Pepper, and finally to the future twilight phase of the project. The applicability and reliability of reservoir modelling at various points in the project life are reviewed. A critical feature of the reservoir management of thin oil column reservoirs has been the almost continuous remapping process as additional data was acquired and the necessity for detailed geological flow unit description. A multi disciplinary team approach has therefore been of great importance in achieving an integrated reservoir management plan.

Foremost in the development success of marginally economic fields such as those in the Airlie Project, has been the application of new technology including MWD logs, gas wetness ratios and modern Simulation tools. The use of reservoir Simulation has been instrumental in the optimisation of horizontal well placement within the thin oil columns which are continually rising as gas caps become depleted. It was concluded from reservoir Simulation studies and appraisal drilling that future horizontal wells drilled in these thin oil columns should be placed as high in the remaining oil column as possible.
Utilization of Horizontal Wells for Secondary Oil Recovery
Authors: Reeves S. R. , Strickland T. A. , Crawford P. B.
Published: December 2007

Horizontal drilling for primary oil recovery has become a routine practice in some areas of the United States, with more than 2,700 wells drilled nationwide1 averaging horizontal extensions of 1,500 to 3,500 feet. Frequently these wells are targeted for achieving a near perpendicular intercept with natural fracture Systems in reservoirs having a substantially vertically fractured matrix. Many such horizontal wells have resulted in oil production rates more than sufficient to payback the higher well expense in as short as a few weeks. This rapid payout has provided the incentive for drilling additional horizontal wells, thus advancing horizontal well drilling technology.

It would appear that horizontal wells may also find application in certain secondary or enhanced oil recovery projects. Primarily for this reason, a reservoir modeling study was performed to determine the possible use of horizontal wells to optimize the performance of such projects. From the study it was leamed that both the length and the Orientation of horizontal wells have a very significant effect on the areal sweep efficiency of commonly utilized oil displacement processes; sweep efficiencies ranged from near zero percent to almost one hundred percent of the pattem area and were found to be dependent primarily upon the well length and Orientation.

The incremental costs of drilling horizontal wells were investigated in combination with the projected increase in oil recovery over vertical wells. The economics of horizontal wells for improved recovery were then evaluated and found to be highly attractive when the horizontal legs were favorably oriented.
Improving Gravel Packing Techniques in Brunei Darussalam Field Trial Results
Authors: Welling R. W. F.
Published: December 2007

Since the IMPAIRMENT TESTS carried out in May 1989 improvements have been made to BSP's operating practices such as better shearing and filteating of the gravel carrier fluid and the introduction of new well bore cleaning procedures. A new earner fluid viscosifier, SHELLFLO-S, was successfully tested. Likewise, pre-packing the perforations prior to running the WWS was carried out either through the TCP string or the perforation washing tool. No significant productivity increase was observed Further with pre-packing were carried out. data are, bowever, not yetavailable.

A Quality Improvement Project addressed the gravel packing process and identified some the possible uses of impairment was finalised. This result in further field trials in which the perforation was incased by either double perforating (21-24 spf) or guns (7". This was done in combination with perforation washing. A furfber move away from s/urry pac/ong fowards convenf/ona/pacWhg us/ng an/n-fne b/ender was made and a few we//s were packed us/ng/ow v/scous bnne as earner f/u/d.
Light Workover
Authors: Rachmat Elwin , Suzanne J. G. , Boibien C. G.
Published: December 2007

The complexity of typical completions in Handil & Bekapai fields, i.e. dual completions in deviated wells to produce selectively 2 to 6 productive layers, leads to very delicate and expensive workovers.

In order to increase oil and gas gain, as well as to increase water-injection points without having to pull out the existing completion string, a light workover (LWO) System has been applied in both fields. LWO operations (which include additional perforations, isolation of perforations or communication by cementation, and gravel packing) may involve either slickline, electrical wireline, snubbing, cementing / gravel packing units or any combination of the above, but neither drilling nor work-over unit is involved. LWO's are the last chance to produce a zone having insufficient potential to justify economically a Heavy Work Over by using drilling or workover unit.

Since 1986 up to August 1992 TOTAL Indonesie has performed 103 LWO jobs which have obtained an additional cumulative production of more than 6.4 million barreis oil and 13.8 billion SCF gas and an additional 10 million barreis injected water.

The total cost for such jobs was 7.2 million USD or an average of 69 620 USD / LWO. Compared to heavy WO's (pulling out the existing completion string & running in hole a new one) which cost between 0.75 to 2 million USD each, LWO is really the cheapest solution as long as the WO goal is achieved.
Interpretation of Pulsed-Neutron Data in Low-Salinity Environments Without Base Logs
Authors: Aldred R. D.
Published: December 2007

Conventional methods for monitoring the movement of formation fluid contacts in low salinity environments, using pulsed-neutron-capture (PNC) logs, employ the "time lapse" technique. This technique is based on the comparison between base logs recorded before production commenced and logs recorded later in the life of a producing well. The recording of a base log requires the well to be re-entered some weeks or months after completion and, in the case of fields which are developed using subsea completions, this is not practical.

This paper describes a technique which was developed to interpret PNC logs in low salinity environments without the need for base logs. The technique involves Computing synthetic base logs from the open hole log Interpretation of a well and the sigma response to each mineral and fluid in the formation. This method has proved successful in the monitoring of changes in oil-water contacts in two fields in the Timor Sea, Jabiru and Challis, both of which have formation water salinities of about 40,000 ppm, NaCl equivalent.

Verification of the accuracy of the technique is provided by means of monitoring the change in natural radioactivity in the formation due to water movement This has been observed by changes in relative gamma ray responses between open hole and cased hole logs beneath the new oil-water contacts.
Microannulus Effect on Cementation Logs: Experiments and Case Histories
Authors: Jutten J. J. , Hayman A. J.
Published: December 2007

Experiments were conducted to study how sonic and ultrasonic cementation logs are affected by microannuii. By creating both gas- and liquid-filled microannuii of known sizes at the casing-to-cement interface, measurements could be recorded and analyzed.

Depending on the nature of the fluid and the size of the microannulus, results showed that all cementation logs were sensitive to microannuii. Gas at the casing-to-cement interface had a very strong effect on the ultrasonic measurement but had minimal effect on traditional sonic Cement Bond Log (CBL) measurement if the microannulus was in the range of one μm. CBL measurement was very sensitive to water-filled microannuii. Ultrasonic measurements were capable of evaluating the quality of the cement behind a water-filled microannuii as large as 100 μm. Liquid-filled microannuii could be identified through the large coupling attenuation measured with multi-spacing sonic tools.

Analysis of these experiments brings new insights to cementation-log interpretation.
Remedial Treatment for Polymeric Damage Removal Provides Improved Well Productivity
Authors: Tjon-Joe-Pin Robert , Brannon H. D. , Rickards A. R.
Published: December 2007

Recent advances in biotechnology have led to the identification ‘and isolation of polymer-specific enzymes. This new technology has been incorporated in the development of improved damage removal systems. The polymer specific reactivity of the new systems provides environmentally safe polymer degradation without causing damage to the formation or tubular goods.

Polymer specific systems have been developed for removal of damage caused by polymers such as cellulose, guar, and starch. The treatments can be applied over a wide range of downhole conditions to polymeric damage resulting from fracturing, gravel packing, or workover operations.

Fracture conductivity and core flow evaluations have shown that multi-fold improvements in permeability are achieved with the new systems. Damaged wells treated with the new systems have experienced up to three-fold improvement in well productivity. A detailed study and analysis of laboratory and field data are presented.
Integrated Drilling Services on a Dynamically Positioned Drillship
Authors: Halkett D. W.
Published: December 2007

A Dynamically Positioned Drillship was chartered by a Major International Operator to conduct a deep water, multi-well / multi country programme. The Integrated Services approach was applied, with the Drilling Contractor responsible for the management of drilling operations and the sub-contracting and managing of up to 21 different services. This paper summarises the execution of this project, and the effectiveness of the Integrated Services (IS) approach on a Drillship drilling remote exploration wells.