bluuebunny/crossref_metadata_2025 huggingface dataset:
A Numerical Study To Evaluate The Use Of WAG As An EOR Method For Oil Production Improvement At B.Kozluca Field, Turkey
Authors: Cobanoglu Mustafa
Published: December 2007

B.Kozluca Field with an OOIP of 138 MMSTB has been producing for more than 16 years. Main producing formation is the carbonate Alt Sinan. Oil gravity is 12.6 °API with a very high viscosity of 500 cp at reservoir conditions. Production mechanism is rock and fluid expansion with a very weak bottom water drive. By the year 2001, the cumulative oil and water production are 3,836,551 stb and 539,059 stb respectively and daily oil production is 570 stb/day with 20 % WC.

In 2000, in order to increase the oil recovery, a re-evaluation and reservoir management study was started. This study was initialized by screening the applicable EOR methods. Since there is a CO2 reservoir at Camurlu Field, which is about 10 km from the B.Kozluca field, study was focused on the CO2 injection. Then, a full field simulation and reservoir characterization study was performed. Firstly, a numerical model was used to predict the oil production by current production scenario and then this model was used to make a sensitivity study to determine a certain CO2 injection pattern, number of the injection wells and the optimum injection rate. Although the initial predictions for different immiscible CO2 injection scenarios give very limited incremental oil due to the very adverse mobility ratio between oil and CO2, this application accelerates the oil production. Then, many different Water Alternating Gas (WAG) scenarios were studied and the results showed that WAG will be better than only CO2 injection. In order to find the optimum injection period many scenarios were studied and 60 days of CO2 injection followed by 30 days of water injection scenario was chosen as the best case. Meanwhile, a parallel study was initiated for the design of the surface facilities and well heads for injection wells of B.Kozluca field, a processing facility for CO2 and produced water at B.Kozluca field and CO2 production and treatment facilities at Camurlu field.

At the end of the integrated reservoir management study, by applying the WAG technique as an EOR method, it was predicted that more than 7 MMSTB incremental oil will be produced with $ 4.25 MM capital investment for surface facilities, additional perforations, pipe line construction and conversion of production wells to injection wells. With this investment, more than $ 20 MM profit will be gained. Pipeline construction between Camurlu and B.Kozluca field has been already started and Camurlu field surface facilities were evaluated and was found to be sufficient for CO2 production and treatment. Other surface facility constructions are being planned for the coming months.
New Technique to Recover By-passed Reserves Above Packer Reduces the Completion Cost and Maximizes the Well Production in ONWJ Field, Indonesia
Authors: Susilo Yoliandri , Wibowo Wahju , Rich David , Priyandoko Pajang
Published: December 2007

This paper will describe the successful application of cement packers in Offshore Northwest Java Sea (ONWJ) field to recover by-passed reserves that are located above the production packer. Previously, conventional completion techniques required a workover to re-complete these new zones. However, due to their marginal reserves or the well still has good production from existing zones (ex: in dual completion case where long string is still a good producer while short string is already shut-in), a workover is not a good option to recover these by-passed zones. A new treatment technique in ONWJ field, Indonesia, has been developed to re-complete and treat these zones that are located above the production packer without pulling out completion strings. Isolation of potential zones is accomplished by cementing in the tubing-casing annulus above the production packer. The cement above the zone replaces the production packer and conventional perforating is then used to complete the well.

The advantages of this technique are: inexpensive (no rig required), no need to wait for the well to achieve economic limit rates before recovering the zones, and - most importantly - it still allows access into the lower completions. On the other hand, the disadvantages of this technique are: less gun penetration (has to penetrate tubing-cement-casing-cement-formation), and workover/sidetracking below packer is difficult to carry out once the packer has been covered by cement.

To date, a total of 7 wells have been reactivated using this technique to recover the zones/reserves. The jobs have been done successfully in both single and dual completions. The average cost was only 20%-60% of conventional workover jobs and savings of up to US$ 400,000 have been achieved. The production results have also been encouraging. These successful results have brought new opportunities for reactivating many more shut-in wells with by-passed reserves that are economically marginal.
PDC Bits and Rotary Steerable Tools - Functional Challenges, Stabilization Requirements and the Establishment of Operational Compatibility
Authors: Mensa-Wilmot Graham , Stacey Brian
Published: December 2007

The introduction of rotary steerable tools1,2 (RST) has drastically changed how the drilling industry plans and executes directional drilling projects. These tools address most of the technical and operational limitations, which previously hindered directional drilling efficiency. With RSTs, changes to wellbore trajectory are made while the drill string is in continuous rotation. This advantage improves wellbore quality, hole cleaning and Rate of Penetration (ROP). It also reduces well bore tortuosity, torque and drag, and eliminates the harmful effects of "negative weight on bit", especially on extended reach3 (ERD) programs.

The benefits listed above can only be achieved if RSTs are used with appropriate bits4,5,6. The development and/or selection of the "right bit type" for an RST application is "not as simple as perceived". This is due to the numerous technical issues - functional challenges, stabilization requirements and operational compatibility - that have to be addressed. To achieve technical and economic success, bits used with RSTs must also address expected formation drillability issues7, in terms of their ROP and durability.

PDC bits exhibit most of the characteristics needed to establish efficient partnerships with RSTs, especially their structural reliability and ROP potential. These attributes are further enhanced by the "absence of slide mode drilling", due to the continuous rotation of the drill string.

This paper will characterize the technical issues associated with the PDC/RST combination, and show how "appropriate PDC bits" address them. It will draw distinctions between bit aggressiveness (BA) and bit instability (BI), and demonstrate how these parameters are affected by well profile specificity and dog-leg (DLS) requirements. In addition, it will identify and evaluate the requirements needed to ensure operational effectiveness on PDC/RST operations. Several field examples will also be discussed.
Multi-Lateral Level 3 and 4 in PDO
Authors: Al-Hady Abdullah
Published: December 2007

ML technology was started in PDO since 1994 where over 240 ML have been drilled in PDO majority of them are level 2. The increasing complexity of well architecture demands more complex ML systems. Many system available in the market are not mature yet and the other do not meet the specific requirement of PDO. As it is known the main drives for this technology is a reduction in UTC by combining wells (One surface casing, one X-mass tree, and one completion) and reduce number of locations hence surface facilities as the pipe lines and headers. PDO activities with ML can be divided into three different applications. Northern fields where there is no hole instability or sand production problem therefore level 2 is of great success. As an example, in Saih Rawl wells the 6 to 8 producing laterals of level 2 from the same backbone is a routine construction. However, in the southern carbonate fields the hole instability and sand production problems exist. To avoid the sand production problem the lateral should be lined up by WWS or PDL, which required level 3 junction. The present of highly unstable shale at the cap rock add more complicity to the system by requiring a high strength junction for ML system. The third application of the ML technology is in deep stringer oil wells and gas wells where a level 6 system could be applied in the future where high pressure is required due to the reservoir high pressure. This article will brief in the experience we have with different ML systems of level 3 and how this drive us for the level 4 MX-select from Smith Red Baron which is initial design to meet our requirement in Amin field. Also this article will show how to go through sand production and shale ingress through the junction where a cemented junction is not appropriated (Flanged Hook Hanger) and the learning points from the first trial.
Isolation of a Horizontal Hole Section in an Openhole Well Using a NonDamaging Temporary Gel Plug to Facilitate Hydrocarbon Production from the Remaining Lateral Section - A Case History from Kuwait
Authors: Khater Mohammed R. , Uddin Shahab , Al-Rubaiyea Jamal A. , Rai Ashish R. , Gazi Naz
Published: December 2007

This paper describes the application of a nondamaging temporary gel system to isolate a part of a horizontal section in an openhole well. The purpose of this application was to provide a cost effective method of isolating a high water-saturated zone of the extended lateral to facilitate the production of hydrocarbon from the rest of the open hole.

The candidate well (R-91) selected for this application was the first extended lateral horizontal well (3000-ft lateral section) drilled as a producer. The well was to be converted to an injector at a later time.

Logging while drilling (LWD) was performed during the drilling phase of this well, and a low-resistivity section was identified along the horizontal lateral. On completion of the drilling, a well test was performed, indicating a high water cut. It was suspected that this water was being produced from this low resistivity section along the lateral hole.

An economical method for confirming and isolating the source of this water influx was needed. Since this was a low-pressure well, an electric submersible pump (ESP) for production had been used. Since low-pressure wells were the norm for this field, ESP completions were commonplace. Different techniques, including use of drillpipe conveyed or coiled-tubing-conveyed production logging tool (PLT) were also considered.

The nondamaging gel plug placed across the low resistivity section of open hole with coiled-tubing allowed the operator to identify and confirm the source of water. The gel plug formed a barrier across this zone, thereby restricting and reducing the water influx.

Presence of a natural fracture was also identified during the drilling phase, and hence, communication between the low-resistivity interval with the oil zone towards the heel of the lateral section was confirmed. Due to non-availability of certain logging tools at the time of requirement along with high costs of using such tools, the proposed gel technique was used as an alternative option. Being a non-damaging pill with greater than 99% regained permeability after cleanup, the well could safely be isolated with this technique. The pill would be dissolved with acid at a later stage when required.

The procedures and the placement techniques of using two-inch coiled tubing and subsequent test results provided insight into the success and the uncertainties involved.

The post-job analysis of results allowed further optimization of these processes, which would facilitate similar applications in the future.

The operator's objective of drilling this well to initially produce as much oil as possible, and then, at a later stage to convert it into an injector to improve the sweep efficiency in the area was achieved as a result of the application of this technique.
Application of Dual Lateral Wells in A Heavy Crude Oil Reservoir
Authors: Centeno A , Barrios J , Arnone M , Lopez J , Gonzalez M , Ramos D
Published: December 2007

This paper presents the PDVSA experience of multilateral wells planning and construction in a heavy crude oil reservoir. In the planning phase, multilateral technology shown to improve the project economics, based on the construction of 12 multilateral wells. Geology, drilling, completion, and workover aspects were evaluated for selecting the most appropriate junction level. Levels 3 and 4 were fully compared. Level 4 junction was selected after the analysis. So far, PDVSA has constructed 9 MLT wells in Bare field. The production results were as planned and the final economics of the project was better than the estimated values. This paper also presents the learned lessons during well operations and concludes that multilateral technology constitutes an economic alternative for the exploitation of this field. Also, this experience contributed to shape the process required for adapting and transferring new technologies in PDVSA drilling operations.
Design of Fibre-Optics Based System for Monitoring of Structural Safety in Drilling Rigs
Authors: Thakur A. K. S.
Published: December 2007

Structural safety of drilling rigs is a matter of major concern for operators. In spite of best industry practices a number of mishaps occur, sometimes taking heavy toll on investments and human lives. At times marine environment is also endangered due to accidents on offshore rigs. The paper presents a system design for altogether a new class of online monitoring system based on optical fibre technology for total rig structure providing ample opportunity to take pre-emptive action for averting mishaps arising due to metal fatigue and excessive overloading. The system will be very useful in the inspection and testing of new rigs. The system finds application in periodic preventive and corrective maintenance and would reduce the inspection time and expenditure. Such a system gains more importance on account of emerging trends in "re-qualification" of offshore drilling rigs.
A New Electronic Firing Head for Slickline Explosive Services
Authors: Taylor Nick , Guevara Juan , Sabine Cedric
Published: December 2007

Using traditional slickline methods, it has not been possible to initiate chemical cutters, detonate perforating guns or any other explosive device, without using a preset pressure or temperature tool. These devices require a survey run and rely on well conditions remaining the same during the live perforating run. Once inside the preset operating window, the firing process is automatic. With these devices, the operation cannot be aborted unless the tool is removed from the operating window or the operating parameters are changed.

A new firing head has been developed that eliminates the parameter-gathering run and gives the operator total control, similar to that in electric-line perforating. This results in a safer operation that allows arming, firing and aborting the operation. The firing head uses field-proven technology and a slickline movement sensor. Safety is also improved by eliminating primary high explosives.

This paper covers the development of the firing head, from initial idea to field introduction, and includes discussion on operation and safety features. The case studies describe the first commercial operations in a southern North Sea field.
Coalbed Methane in the Illinois Basin: Development Challenges in a Frontier Area
Authors: Lombardi Tracy E. , Lambert Stephen W.
Published: December 2007

Coalbed Methane (coal gas) is in its second wave of development in the United States. Twenty years ago, it was an unconventional gas play most operators stayed away from. It grew however to be one of the hottest plays of the early 1990’s. The development of successful coal gas fields has come as a result of favorable economic conditions, but also due to strong cooperative efforts among industry and research and development organizations in sharing technical information and experience, and designing research projects specifically geared toward technical issues. During this first wave of development numerous areas containing substantial coal gas resources were left undeveloped. These frontier areas in the lower United States have been estimated to contain over 677 Tcf of coal gas.

The Illinois Basin is still considered a frontier area. The basin was formally evaluated for its coal gas potential in 1979, at which time the amount of Pennsylvanian-age coal was estimated at ~365 billion short tons, having a potential in-place coal gas resource of up to 21 Tcf. However even with such a large potential coal gas resource, only small areas within the basin have seen exploration programs during the past 20 years. Methane gas has been produced from wells drilled into abandoned coalmines in the past providing an energy resource for local uses, but less than 35 actual coalbed gas wells have been drilled in the basin through December 2000.

The Illinois Basin encompasses approximately 53,000 mi2, and is in close proximity to numerous large gas storage fields and gas markets. Having a long history of hydrocarbon activity, the basin contains a well-developed interstate pipeline infrastructure. What are the main factors hindering coal gas exploration in the Illinois Basin? What are the technical challenges that operators have yet to overcome? Will a coordinated basin-wide industry / research effort required to develop more confident estimations of this resource?

This paper focuses on these questions by addressing, the current perceptions of the coal gas resource, the historic and current exploration activity, and the mechanisms effecting coal gas development. As a result, the current technical challenges facing operators are identified. Opportunities to participate in the collection and evaluation of comprehensive reservoir characterization data sets in the basin are presented.
Identifying Best Practices in Hydraulic Fracturing Using Virtual Intelligence Techniques
Authors: Mohaghegh S. D. , Gaskari R. , Popa A. , Ameri S. , Wolhart S. , Siegfried R. , Hill D.
Published: December 2007

Hydraulic fracturing is an economic way of increasing gas well productivity. Hydraulic fracturing is routinely performed on many gas wells in fields that contain hundreds of wells. Companies have developed databases that include information such as methods and materials used during the fracturing process of their wells. These databases usually include general information such as date of the job, name of the service company performing the job, fluid type and fluid amount, proppant type and proppant amount, and pumped rate. Sometimes more detail information may be available such as breakers, amount of nitrogen, and ISIP, to name a few.

These data usually is of little use if some of the complex 3-D hydraulic fracture simulators are used to analyze them. But valuable information can be deduced from such data using virtual intelligence tools. The process covered in this paper takes the available data and couples it with general information from each well (things like latitude, longitude and elevation), any information available from log analysis and production data and uses a data mining and knowledge discovery process to identify a set of best practices for the particular field. The technique is capable of patching the data in places that certain information is missing. Complex virtual intelligence routines are used to insure that the information content of the database is not compromised during the data patching process. The conclusion of analysis is a set of best practices that has been implemented in a particular field on a well or on a group of wells basis. Since the entire process is mostly data driven we let the data "speak for itself" and "tell us" what has "worked" and what "has not worked" in that particular field and how the process can be enhanced on a single well basis. In this paper the results of applying this process to Medina formation in New York State will be presented. This data set was furnished by Belden & Blake during a GRI / NYSERDA sponsored projects.

This process provides an important step toward achieving a comprehensive set of tools and processes for data mining, knowledge discovery, and data-knowledge fusion from data sets in oil and gas industry.
Continuing Education Needs in Exploration and Production
Authors: Domínguez-Vargas G. , Camacho-Velázquez R.
Published: December 2007

This paper describes the findings of a technological diagnosis in a national oil company, aimed at detecting professional development needs, the set of actions taken to solve these, and the evaluation of these measures by another needs-identification procedure.

With these results, future actions are proposed to consolidate the advances and to drive the company to the next level of professional development.
A Method for Analyzing Multiple Factor Experiments - Its Application to a Study of Gun Perforating Methods
Authors: Vogel L.C.
Published: December 2007

Frequently in engineering research, problems involving a large number of variables (factors) are encountered. A traditional method of interpretation is for the project engineer to present his results in the form of families of curves obtained by varying factors one at a time. When several values (called levels) are required to characterize each variable properly the number of test points necessary may become prohibitive. It is possible under certain conditions to test only a portion of all of the combinations of the factors and still draw reliable conclusions.

This paper describes and demonstrates the use of a powerful statistical method for handling problems of this type. The accurate and fairly inexpensive solution to the laborious calculations was made possible by the use of an electronic data processing machine. The first part of the paper deals with the method of analysis in sufficient detail so that its application in general engineering research problems can be seen. The second part describes the actual application to a study of gun perforating methods.

Introduction

One of the most perplexing problems faced by engineers is that of properly interpreting the results of experiments involving large numbers of supposedly independent variables. Reservoir engineers are constantly attempting to evaluate the effect that the various phases of well completion have upon oil production. Research engineers design laboratory experiments to evaluate various factors in as economic a manner as possible. The classical method of studying the effect of controllable factors is to vary a single factor at a time. This "single-factor-at-a-time" method is extremely inefficient when compared to the technique called factorial design. For a simple experiment involving two factors, each at two values (levels), the use of factorial design results in an increase in precision of 50 per cent over that in the equivalent single-factor-at-a-time experiment and, as the example becomes more complicated, the difference in efficiency between the two methods increases markedly. This advantage of factorial experiments, sometimes called "hidden replication," is based on the fact that all of the observations contribute to the determination of the effect of each factor. In the single-factor method, on the other hand, only a small proportion of the total number of observations is used.

When factors do not operate independently the are said to interact. An example of interaction between factors can be seen in PVT studies where the effect of varying the temperature is dependent upon the pressure of the system.
An Evaluation Method for Screen-Only and Gravel-Pack Completions
Authors: Hodge Richard M. , Burton Robert C. , Constien Vernon , Skidmore Valerie
Published: December 2007

Screen-only and screen with gravel-pack completions have become more commonplace in long horizontal wellbores in poorly consolidated reservoirs. Several of the formations currently being completed pose challenges in selecting effective sand-control screens due to their non-uniform particle size distributions and the large amount of very small particulates.

Early screen and gravel-pack studies, from which common scaling factors were derived, did not always contain the smaller particle sizes that are encountered in poor quality reservoirs. Later studies have shown that both the fines content and the uniformity of the sand impact the performance of the completion7-13.

This paper presents an evaluation method for screen-only and gravel-packed completions utilizing formation sand samples. The method determines the amount of solids produced through the screen and the change in flow capacity of the screen and formation sand pack with increasing stress. The flow capacity data is useful in estimating production changes as wellbores collapse around the screen and the formation porosity around the screen decreases.

The amount of formation particles that pass through the screen or the gravel-pack and screen is useful in estimating the solids production. Data is presented which illustrates the amount of small particles, which can penetrate wire-wrapped and premium screens, along with gravel-packs and gravel-packed screens.

Data will be compared for gravel-packs based on conventional scaling factors of 5-6 times the median diameter and other scaling factors.
Environmental Protection in Work-Over Completion Operation Using Pitless and Zero Cost.
Authors: Sauman M. , Law B. , Hamdani A. , Foster J.
Published: December 2007

Pertamina / Vico Indonesia made the decision to minimize the environment impact from its Work-over completion operation in East Kalimantan. In the past, Work-over completion operations typically used a large location with a brine or salt water as work-over fluid in work-over completion operation. All waste from the operation was dumped into a large pit. The drilling and work-over department is now applying new technology to continuously improve and achieve ‘pit-less work-over completion’ or ‘zero waste discharge’ and therefore minimize the environmental impact. The intention was to achieve these environmental goals with an overall cost saving, as the increased costs would be offset by cost reductions. The project is being implemented in several stages.

The first stage of the environmental protection project is to use additional water clarification equipment and centrifuge to treat location drainage and rainfall. This process allows the clean water discharge from the process to be recycled for the rig operation or disposed to the environment. The solid waste from the centrifuge is tested to ensure the solid discharge is acceptable and landfill in the catch pit. Locations are designed and built to channel the rainwater. The catch pit is build to collect the liquid waste and oil pollution. Oil or condensate is skimmed and burnt at the flare pit

The second stage of the project used a water clarification, filtration unit to recover salt water or brine from the old well to be recycled for work-over completion operation. The system and waste disposal is proven and pit-less work-over completion has been implemented in VICO operation.

During the project, special effort has been given to confirm the water clarification and remediation results. In order to meet Indonesia regulations and other applicable regulations and standards, water and solid waste are tested to ensure discharges are acceptable. The work-over completion area was planted with a variety of native plants.

Using the above technology Pertamina / Vico Indonesia are working to minimize the environmental impact in work-over completion operation. There is "Zero" environmental cost as the cost of the service is offset by reduced costs for land, construction, reclamation, and re-greening.

This paper describes the minimization of environmental impact in work-over completion operation with zero cost.
The Importance of a Health Management Program in China
Authors: Raj Reuben D. , Jackson Mark
Published: December 2007

More and more international companies regard people as the main asset of the business. In many cases, medical evacuation and emergency response often get more emphasis when a foreign company starts its operations in the oil and gas industry of the People's Republic of China. However, this view can be perceived as reactive. To prevent losses, a proactive Health Management System is essential to treat health-related problems early.

China, with her great diversity, offers a new market with endless business opportunities. The acceptance of China into the World Trade Organisation will no doubt attract more foreign investment into this new business frontier. Health, among other issues, is an important element for any foreign company to consider before commencing operations.
Mechanical Equipment Surveillance
Authors: Broyles George W.
Published: December 2007

Surveillance of gas facility mechanical equipment is a vital part of Exxon's current operation. Proper utilization of this equipment presents a significant opportunity in cost control, presents a significant opportunity in cost control, optimizing revenue and minimizing investment requirements. If reciprocating compressors and centrifugal compressors are not operated properly and adequately maintained, oil production, gas production and gas plant liquids will be curtailed production and gas plant liquids will be curtailed accordingly. Availability of horsepower when needed is an obvious requirement for maximizing revenue from production of oil, gas and gas plant products.

Introduction

This paper describes a mechanical equipment surveillance program that has been developed in the East Texas Division of Exxon Co., U.S.A. Production Department. The statistics that are Production Department. The statistics that are quoted refer only to this division, and although similar programs are in effect in other divisions within Exxon's Production Department, only the specific program as developed by the East Texas Division is described.

The existing machinery maintenance program was begun in 1968 with the establishment of an engineering surveillance group at the division level. By 1978, surveillance personnel had also been added to the engineering groups in the four district offices. There is a total of 463,000 BHP in 390 units in gas compression and generator service spread over one 75,000 square mile area of this division.

The machinery maintenance system can be divided into four basic functions:Predictive/Preventive MaintenancePerformance monitoringTechnical inputDevelopment of on-site maintenance capability

These four facets of the system are discussed below, followed by a summary of the benefits that have been accrued from the system to date.

I. PREDICTIVE/PREVENTIVE MAINTENANCE PREDICTIVE MAINTENANCE PREDICTIVE MAINTENANCE

Reciprocating Compressors

Exxon has utilized predictive maintenance techniques since 1968 when the first Beta Engine/ Compressor Analyzer (E/CA) was purchased. The Beta analyzer was developed by the Southwest Research Institute of San Antonio, Texas to analyze reciprocating engines and compressors in operation. The analyzer became a reality in January, 1965 when Beta Corp. of Dallas, Texas began marketing it.

The Beta E/CA is comprised of three main units which are:The motion transducerThe indicator unitThe auxiliary unit

Other basic components used with the Beta E/CA are the synchronizing light, pressure transducers, oscilloscope camera and ignition and vibration pickups. pickups.
An Investigation of Asphaltene Instability Under Nitrogen Injection
Authors: Jamaluddin A. K. M. , Joshi N. , Iwere F. , Gurpinar O.
Published: December 2007

As a part of an integrated improved oil recovery project, it was required to evaluate asphaltene formation arising from contacting nitrogen gas with the reservoir fluid. This paper discusses the experimental work associated with the asphaltene evaluation.

The subject reservoir was known to have operational problems due to asphaltene precipitation during primary production. Hence, laboratory experiments using the transmittance of an optimized laser light in the near infrared (NIR) wavelength (~1600 nm) were used to first define the pressure-temperature regions of asphaltene instability of the reservoir fluid. Subsequently, several light transmittance experiments were conducted to evaluate the asphaltene instability regions by contacting various molar concentrations (5, 10, & 20%) of nitrogen gas with the reservoir fluid. Also, measurements were conducted to quantify the bulk precipitation of asphaltene with various molar concentrations of nitrogen.

Results indicated that nitrogen gas aggravated the asphaltene instability, and also, increased the bulk precipitation amount with increasing concentrations of nitrogen gas in the reservoir fluid. The aggravated asphaltene instability could potentially nullify any expected benefits of improved oil recovery with nitrogen injection as pressure maintenance.
The Hybrid Drilling System: Incorporating Composite Coiled Tubing and Hydraulic Workover Technologies into One Integrated Drilling System
Authors: Coats E. Alan , Farabee Mark
Published: December 2007

Historically well drilling operations have been based exclusively on steel pipe. Recently a drilling system that combines composite coiled tubing technology and hydraulic workover technology has been introduced. This paper examines the operating experience for the system and its implications for the future.

By using composite pipe with embedded conductors, the system achieved uninterrupted real-time two-way communication with the downhole tools. This allowed a step-change improvement in the knowledge of dynamic wellbore conditions and in the control over downhole systems. New procedures were developed to assimilate and use this increased functionality. These procedures include both geosteering and real-time system diagnostics from remote locations.

Incorporating a hydraulic workover (HWO) jacking system as an integral part of the drilling unit also expanded the operating envelope and functionality of the entire drilling system. This revolutionary full-system development encountered numerous challenges, many of which are related to the unique properties of composite pipe in difficult hole conditions. The technological solutions to these challenges are examined in depth.
A Realistic Approach For Capital Expenditures Analysis
Authors: Choudhary Bijoy K. , Kellstrom William A.
Published: December 2007

This paper briefly reviews the various financial analysis techniques to judge capital expenditure projects. Most of these methods in their basic forms, however, fail to determine the real returns to a company from such capital investments. A procedure is outlined to incorporate the concept of real returns for a realistic appraisal of a capital expenditure project.

Introduction

The capital expenditures in the petroleum industry are analyzed with the help petroleum industry are analyzed with the help of several techniques, such as discounted cash flow rate of return, net present value, payback and operating rate of return. Among the lesser known and practiced methods are E.A.A. (equivalent annual amount) rate of return and some ratio of present value of profits to present value of investments. Beyond the apparent present value of investments. Beyond the apparent advantages and disadvantages, these methods in their basic forms fail to account for the real loss of returns due to inflation and other factors which may be unique to a company.

This paper describes the existing financial analysis techniques and then discusses a method which incorporates the concept of real returns which are also adjusted for the company's historical performance. When combined with some form of computerized simulation techniques, this suggested approach can perform a very effective and useful role in proper selection and ranking of the capital expenditure projects. This may also be able to achieve optimum returns under any given set of assumptions. A comprehensive example shows the various profitability measures and their usefulness and profitability measures and their usefulness and limitations. It is then expanded to show the real rate of return which ought to be the true measure of capital expenditure projects. projects.

DISCUSSION OF PROFITABILITY MEASURES

The various methods to determine the profitability of a project are summarized profitability of a project are summarized below.

DCF RATE OF RETURN

The discounted cash flow (DCF) rate of return, also known as internal rate of return, is the discount rate which will make the present value of all cash outflows equal to the present value of all cash inflows.
Optimization of Barite Dissolvers by Organic Acids and pH Regulation
Authors: Lakatos I. , Lakatos-Szabó J. , Kosztin B.
Published: December 2007

The data in literature clearly proved that the polyamino carboxylic acids (PACAs) are promising barite dissolvers. So far, however, only the ethylene-diamin-tetraacetic acid (EDTA) and the diethylene-triamin-pentaacetic acid (DTPA) were studied and tested in detail. Therefore, an extensive research programme was launched to compare the potential of other barite dissolvers. The laboratory study were also extended to nitrilo-triacetic acid (NTA), diamino-cyclohexane-tetraacetic acid (DCTA), dioxaoctamethylene-tetraacetic acid (DOCTA), hydroxyethylene-diamin-triacetic acid (HEDTA) and triethylene-triamin-hexaacetic acid (TTHA).

Dissolving capacity of each compounds was determined as a function of concentration for barite and reservoir rocks. The absolute and relative dissolution selectivity and the matrix effect of formation rocks were precisely analyzed. Independent variable of the measurements was the pH and type of organic acids used as complex-forming promoters. In the batch type studies oxalic acid (OXA), malonic acid (MOA), maleic acid (MEA), succinic acid (SUA) and tartaric acid (TARA) were tested. It was concluded that the performance of well treatment methods (mitigation of formation damage, removal of barium sulfate scales, etc.) based on application of polyamino carboxylic acids can significantly be increased by adding sodium (potassium) hydroxide to the complex-forming agents and setting its concentration to optimal level. Application of organic acids jointly with polyamino carboxylic acids, however, could not be justified if the dissolver system had already been optimized by alkali addition. Thus, from practical point of view it has to be emphasized that optimization of barite dissolving methods by pH regulation is much more efficient and cost-effective than adding multi-functional organic
Acid Removal of Scale and Fines at High Temperatures
Authors: Huang T. , McElfresh P. M. , Gabrysch A. D.
Published: December 2007

With the onset of water production, fines are usually mobilized to the wellbore, resulting in screen plugging. Fines-plugged screens and/or gravel pack can then accelerate scale precipitation, especially in high-temperature formations. Due to the type of metallurgy, long acid contact times and high acid sensitivity of the formations, removal of the scale with HCl acids has been largely unsuccessful. In high-temperature wells, the choice of acid must be done such that the formation and the completion are not damaged, but the scale and the fines are removed. A series of tests conducted on screens and clay-rich cores show that a new organic acid system, which is highly biodegradable, can successfully remove the calcium carbonate scale and fines to stimulate production. Core flood testing demonstrates that this organic acid system can effectively remove calcium carbonate scales and fines at temperatures up to 204°C(400°F). In addition to its reactivity, the acid system, when combined with corrosion inhibitor, exhibits very low corrosion at high temperatures. Corrosion tests show that at 177°C (350°F), the corrosion rate caused by this organic acid is 0.00049 g/cm2 (0.001 lb/ft2) on 22-Cr for 16 hours. Acid soaking to completely remove scale prior to removal of fines is now possible at temperatures in excess of 121°C (250°F). Successive removal of plugging fines from screens can then proceed without further damage to the integrity of the screen.
Stimulating Depleted HP/HT Sand Screen Completions using Coiled Tubing
Authors: Munro C. , Allam R. , Erbil M. M. , Law D.
Published: December 2007

The Marnock Field contains four near horizontal gas condensate producers containing open hole dual wire wrap sand screens. Virgin pressure was 9123 psia but has dropped significantly on three wells to as low as 2200 psia. Reservoir temperature is 310°F. Pressure build up and material balance data showed limited inflow from the Marnock wells, and this was thought to be due to possible wellbore and sand screen mud blockage as only 50% of the drilling mud was recovered on initial well clean ups. Platform based stimulations were conducted in three wells to remove wellbore mud damage and potential sand screen mud blockage. Stimulation techniques consisted of a coiled tubing chemical placement from above the sand screens, a surface bullhead treatment and a coiled tubing sand screen jet wash. Barite attacking chemicals were deployed as the main treatment, including diversion for the bullheading operation.

Preparation, planning and execution of these stimulations have been complex given the potential to access un-depleted virgin reservoir pressure intervals. Well flow back and clean up post chemical deployment was critical and extensive chemical compatibility trials were carried out to ensure no damage to the formation or the process plant was incurred. A temporary clean up package including a high pressure cyclonic de-sander was used to separate flowback products and protect the process plant from solids contamination.

No significant well intervention operations had been conducted previously on the Marnock field on a non–rig basis apart from slickline operations. The challenges faced with installing and operating a full coiled tubing package including support tower and clean up package were substantial. Robust contingency measures were required to address the issues of stuck pipe, pipe cutting, well kill and high-pressure zones. Contingency innovations included the design and manufacture of an explosive cutter suitable for the heavy wall tapered coiled tubing. A special kill pill was also formulated for use with Cesium Potassium Formate in the event of a high-pressure well kill. Platform modifications were also required to enable the tie in of large diameter high and low pressure relief lines to the existing facilities.

As a result of the stimulations the Marnock Field has increased production potentials by 105 mmscf/d of gas and 6500 stb/d of associated condensate, equating to an increase of 25,000 boe/d.
New Empirical Friction Loss Correlation for Foam Fluids in Coiled Tubing
Authors: Khade Sudhakar D. , Shah Subhash N.
Published: December 2007

Friction losses for foam fluids in coiled tubing are not the same as that of in straight tubing. The flow properties of the foam are also very different than that of conventional two-phase fluids7. Factors like foam quality, liquid phase viscosity, flow rate, gel concentration, temperature, and curvature of pipe strongly affect the frictional behavior of foam fluids. The present work discusses and analyges friction pressure losses and rheology, and friction loss correlation development for guar based foam fluids through coiled tubing.

The present study investigates frictional pressure losses in coiled tubing for polymer based foam fluids. The experiments are conducted using guar gel and guar foam employing a pipe flow viscometer at 1000 psig. Foams are prepared and tested for qualities 0 to 80 % at various shear rates using temperatures from 100 to 200 °F. Three polymeric foam solutions are examined for their frictional pressure losses related to their flow behavior in coiled tubing.

The experimental data of differential pressure drop and flow rate converted to Fanning friction factor and Reynolds numbers respectively are used to obtain new empirical correlations to predict Fanning friction factors. These empirical friction loss correlations are function of foam liquid phase properties and curved geometry, and are applicable for the range of shear rates investigated. Significant increase in friction pressure loss is observed in coiled tubing compared to that in straight tubing. Empirical friction loss correlations can be used to predict an accurate Fanning friction factor for foam fluids in coiled tubing.
Improved CT Operational Efficiency by Use of Detailed Planning
Authors: Laun Lyle , Young Steve , Sund Jon-Arild , Vibjorn Dagestad
Published: December 2007

Offshore well operations in the North Sea involve many contractors and require a lot of co-ordination with the platform organization. Well shut-in time is a critical factor because the wells are producing high volumes (up to 56 000 bbl/day initially). Due to this, a project group was formed to improve the efficiency of coiled tubing operations on the Heidrun field. The field center is a Tension Leg Platform (TLP) at 330 m water depth. Because of rig movement, a complicated rig-up structure with heave compensation is used. On most operations, both coil tubing and wireline is used throughout the different operational phases. This comes in addition to pumping and return handling equipment. A lot of equipment is rigged up in a relatively confined area.

The project group started off with identifying all operational steps and finding the critical path. Areas with high potential for savings were identified and the cost for proposed improvements were calculated. Systematic implementation of improvements to the rig-up equipment and procedures gave a reduction in the rig-up time from 82 hours down to 11.5 hours over a 6-month period. As an extra bonus, the operations were carried out at a higher safety level than before. The savings for the client were calculated to USD 450 000 per well, whilst the cost of new equipment, modifications and implementation was USD 110 000.
Development of a Stiff-String Forces Model for Coiled Tubing
Authors: McSpadden A. , Newman K.
Published: December 2007

A mathematical model of tubing forces is proposed which accounts for the bending moment due to stiffness of the coiled tubing (CT) string. The models commonly used in the design of CT operations have typically ignored tubing stiffness. Exclusion of tubular stiffness effects in such "soft string" models has not typically detracted greatly from the accuracy of predicted drag and torque loads. However, CT is being used increasingly in applications such as pipeline workover which may be characterized by unusually small bending radius. In these cases the exclusion of bending stiffness may be result in increased error. The calculation of CT bending moment for CT should also account for plastic bending and residual stresses incurred at the guide arch and reel. Example calculations are presented to evaluate the usefulness of the proposed "stiff-string" model for CT job design.