bluuebunny/crossref_metadata_2025 huggingface dataset:
Fluid Leakoff and Net Pressure Behavior of Frac&Pack in High-Permeability Viscous Oil Reservoirs of the Duri Field, Indonesia
Authors: Fan Y. , White D. E. , Aimar A. , Satyagraha M. T.
Published: December 2007

Frac&pack has become a preferred completion method for the Duri field in Indonesia, where the reservoir is shallow, highly permeable and unconsolidated containing heavy viscous crude. This paper presents simulation of fluid leakoff and net pressure behavior for the frac&pack treatments in the Duri field. Several issues concerning selection of fracturing fluids and proppant, fracture dimensions and treatment designs are also discussed in the paper.

A pressure-dependent leakoff model that is based on a transient flow of a polymer solution displacing a reservoir fluid is presented and coupled with a fracture mechanics model to investigate the interactions among the leakoff, net pressure and created fracture dimensions during different stages of frac&pack treatments. The results indicate that the leakoff is controlled by reservoir fluid viscosity and is dependent upon the rock-mechanics properties and the mobility ratio between the invaded solution and the reservoir fluid. In the absence of filtercake, the traditional leakoff notion using the concept of a constant leakoff coefficient fails to capture the transient behavior of polymer invasion and reservoir fluid compression. Because of high sensitivity to leakoff and the rock-mechanics properties, the net pressure behavior is also quite different from the one anticipated. For the typical formation with an elastic modulus of 50,000 to 100,000 psi in the Duri field, the net pressure is in a range of 20–40 psi during fracture propagation. The simulation also indicates that the net pressure over 200 psi would result in desirable fracture widths for Duri field applications.
Zonal Isolation in Stimulation Treatments and Gas/Water Shutoff Using Thermally Compensated Inflatable Packers and Plugs
Authors: Wilson Paul , Hoffman Corey E.
Published: December 2007

This paper provides laboratory and field-test results of a thermally compensated fluid-inflated packer system. This system greatly reduces the chance of sealing-element failure when inflatable packers or plugs are used where the borehole fluid changes temperature more than 50° F (10°C). To date, a primary cause of failure in achieving zonal isolation while using inflatable packers and plugs is the change in temperature of the borehole and inflation fluids once the packer is set.

Thermally compensated inflatable packers are an innovation in inflatable packer technology. These packers act in a manner unlike conventional inflatables, which are susceptible to temperature changes as little as 50° F (10°C) between borehole and internal fluids. These temperature changes can cause the fluids inside conventional inflatable packers either to expand and rupture the element or to contract and cause the element to lose its seal on the casing wall. Qualification tests and resulting data will be presented as well as data acquired after a thermally compensated inflatable plug system was deployed in a water injection well.

Possible applications include those in which a fluid inflatable packer, straddle packer, or plug would be used and subjected to temperature changes in excess of 50° F (10°C).

The introduction of thermally compensated inflatable packers offers a more technically effective, economical means of zonal isolation in almost any cased-hole application. This technology is equally applicable for openhole applications.
Improved Hole Cleaning and Reduced Rotary Torque by New External Profile on Drilling Equipment
Authors: Boulet J. G. , Shepherd J. A. , Batham J. , Elliott L. R.
Published: December 2007

This paper will describe the successful application and effects of completely new Hydromechanical Cleaning and Hydrodynamic Bearing profiles machined externally on drilling equipment to improve hole cleaning and reduce rotary friction. Qualification programmes, including initial proving trials on a test rig, computational fluid dynamics and cuttings transportation flow loop tests, will supplement details from successful field operational use of this equipment.
20-Plus Years of Tuscaloosa Drilling: Continuously Optimizing Deep HTHP Wells
Authors: Shaughnessy J. M. , Locke H. A.
Published: December 2007

Drilling the Tuscaloosa formation in Louisiana was as challenging as any area drillers worked 20 years ago. It was one of the most active areas in the U.S. Problems that were new at the time such as gas solubility in oil base mud, sulfide stress cracking of tubulars, pressure regressions and low margins between the fracture pressure and pore pressures resulted in numerous well control problems and high cost wells. Activity decreased in the mid 80's when the gas price did not encourage operators to challenge the drilling risks. BP Amoco is still successfully drilling to 22,000' into to 16,000 psi, 380°F reservoirs that are now depleted over 10,000 psi.

This paper will address steps taken to optimize the drilling operation and continue making the wells economical. First, drilling problems such as stuck pipe, lost returns, drill string failures and well control had to be minimized. Next, successful cement jobs were required and have resulted in the highest rate completions in the history of the Trend. All objectives had to be achieved in a safe manner with little impact on the environment.
Application of Novel Downhole Hydraulics Software to Drill Safely and Economically a North Sea High-Temperature/High-Pressure Exploration Well
Authors: Thorsrud A. K. , Ekeli Ø. , Hilbig N. C. C. , Bergsvik O. , Zamora M.
Published: December 2007

Understanding and predicting the downhole hydraulics behavior of a drilling fluid are important for successful drilling and avoiding wellbore instability, well-control situations, and lost circulation. This is especially critical in a drilling environment where invert emulsion drilling fluids are exposed to high temperatures and pressures, and the operating window between pore-pressure and fracture gradient is narrow.

A North Sea well drilled under HTHP conditions (350°F, 14,000 psi) realized the time and financial benefits of a wellsite concept involving a hydraulics engineer and a fit-for-purpose software program for accurately predicting downhole pressures while drilling and tripping. Downhole equivalent static densities up to 18.0 lb/gal were required with a fracture gradient of only 18.5 lb/gal. ECDs were carefully monitored and tripping speeds were optimized based on software pressure predictions. Computer simulation was particularly valuable, and even necessary, when downhole temperatures exceeded the thermal limit for the pressure-while-drilling tool.

Accurate prediction of downhole pressures while drilling and tripping reduced well observation time while avoiding well-control and lost-circulation incidents. Subsequent implementation of this technology in a nearby field contributed to estimated cost savings of US$ 3,000,000.
To the Limit and Beyond - The Secret of World-Class Extended-Reach Drilling Performance at Wytch Farm
Authors: Meader Tony , Allen Frank , Riley Graham
Published: December 2007

The paper describes how the extended reach drilling team at BP Amoco's Wytch Farm development on the South Coast of England met the challenge of drilling and completing technically advanced ERD wells in an increasingly difficult cost and performance focused environment. The key element in this success was the ability to continue developing new technology, while at the same time adopting a technical limit approach to performance delivery. Focusing attention on the individual components that make up a well allowed the team to build on the reliability and experience of using rapidly maturing technologies. It also gave the team confidence in the management of the risks associated with the application of new technologies and more importantly allowed the team to fight back and recover from events that would ordinarily provide justification for well programme timings and costs to slip.

The paper will draw on the experience of three wells drilled from August 1998 to August 1999. M-14 a 9,600m water injection well; M-15 a multilateral well with one lateral drilled to 8,900m and the second to 6,700m;

and M-16 a record breaking ERD well drilled to 11,278m.

The techniques and technologies discussed will be; building a highly motivated team that can manage risk, perform consistently and perform safely; rotary steerable systems; torque and drag simulation and control; casing and liner floating techniques; ECD and mud loss control; multilateral junctions at high angles and downhole flow control completions.

In conclusion the paper shows how powerful a team can be in delivering significant performance improvements even towards the end of a 6 year 17 well development.
Intelligent Recompletion Eliminates the Need for Additional Well
Authors: Lie Ole Henrik , Wallace Wayne
Published: December 2007

The wells in the Gullfaks field, operated by Statoil in offshore Norway, produce from several reservoirs, with the largest reserves being found in the Brent, Cook and Statfjord sands. Only one well in the field, Well C-29, produced from the Lunde formation.

Although Well C-29 intersected the Statfjord formation, commingled production could not be considered since differing pressure regimes, the productivity index, and expected watercuts ruled out this possibility. When the well economics from Lunde formation production became unfeasible, the original plan had been to plug and recomplete the well in another zone. Rather than follow the originally planned well scenario, an innovative technology that introduced a surface-controlled downhole choke system was suggested and subsequently used. This paper will discuss the recompletion of this well.

The new system had the capability to provide two important benefits. It would not only allow commingled production, not possible before, but would save a dedicated Statfjord well slot. The system, incorporating a number of zonal isolation packers and adjustable downhole chokes, each independently controlled from surface, would provide this well with the means of selective or simultaneous production.

The recompletion operations were to be divided into two major parts with the first using hydraulic workover (HWO) to accomplish the through-tubing zonal isolation and tubing-conveyed perforating (TCP) operations. The second operational phase was to be performed with a drilling rig, which would pull the existing completion and run the new completion, employing the zonal-isolation control system.

The completion was successfully installed, and the well is currently a commingled producer with all downhole systems functioning and communicating as planned. The installation proved to be economically favorable, and production plans for the area have been revised to take full advantage of the enhanced reservoir data that has been generated from the well due to the new "intelligent well" completion technology. Of particular significance is the fact that this is the world's first recompletion in which intelligent well technology has been used.
First Multilateral Application in a Deep Devonic Gas Field in the North of Argentina
Authors: Piasco Luis E. , Eguia Hugo V. , Roca Eduardo Perez
Published: December 2007

The purpose of the paper is to show the first experience in drilling a multilateral well in a depleted, highly-fractured Devonian reservoir in the North of Argentina (Salta province). The well was drilled and a dual completion device was run successfully to produce one million cubic meter of gas from each one of the two branches of the well. The total cost of the well was $18.1 MM compared to the $14.5 MM for a single vertical well in the same field. The KOP for the first branch was at 2815 m with a length of 1001-m (TMD). For the second one the KOP was 2763 m with a length of 951 m (TMD). The well was completed as a MLT level 3 with the possibility to be changed to a level 5 in the future. A new whipstock technology was applied in the country for the first time. The paper will show casing design, application of the RWD technology, drilling operation sequence, Whipstock operations (difficulties and how they have been solved) time and total operation costs. Another interesting topic to be explained is the different behavior experimented in each branch regarding the fluid loss in the depleted zone. The results to be shown are the cost savings due to the replacement of two wells by one in a highly difficult logistic zone, the relatively new technology applied successfully in a deep highly deviated MLT well, and the improvement in casing design due to the RWD application in a highly tectonic zone
Unintentional Compensator Lockup Risks, Consequences and Measures
Authors: Storegjerde D. , Sandbu P. , Kvernmo E. , Simmenes R.
Published: December 2007

Unintentional compensator lockup is a well known and industry wide problem, which has received recent attention, following several serious incidents in the North Sea. As similar systems are used worldwide, there is no reason to believe that the failures seen in the North Sea are isolated occurrences. There may however, be some correlation with the severe sea conditions experienced, especially during the winter months, but most geographical areas have such seasons. When using the crown compensator during normal drilling operations, the consequences of an unintentional lockup may be limited. When the rig is rigidly attached to the seabed in connection with e.g. drill stem testing or sub sea completions or interventions, the consequences can be much worse. This paper briefly examines the consequences of three such incidents and details some of the risk and consequence reducing measures implemented to combat the problem. Risk reducing measures includes the modifications made to the existing compensator, while consequence reducing measures discuss the development of new technology to provide redundancy. The objective is to raise the awareness of the possible consequences of a compensator failure and hopefully stimulate increased focus on this critical system.
The Application of Rotary Closed-Loop Drilling Technology to Meet the Challenges of Complex Wellbore Trajectories in the Janice Field
Authors: Edmondson John , Abbott Chris , Dalton Clive , Johnstone John
Published: December 2007

It is usual for initial development wells on marginal fields to follow a conservative drilling programme using conventional technology with known drilling performance. In the case of the Janice Field situated in block 30/17a of the UK North Sea it became apparent, following field appraisal, that to effectively exploit the reservoir it was necessary to drill complex 3D well trajectories. Such wells would require significant directional work with large associated costs. Specific challenges included high torque and drag profiles, slow rates of penetration, limitations of conventional directional drilling techniques, tight target tolerances and the requirement for effective reservoir navigation.

After careful consideration, the operator, Kerr-McGee North Sea U.K. Limited determined that the application of Rotary Closed Loop Steerable (RCLS) technology was part of the appropriate technical and economic solution for the drilling of these wells.

This paper describes how the combination of RCLS and conventional drilling technology was used to achieve the field development objectives. This provided a unique opportunity to make a direct comparison between RCLS and conventional steerable technology on similar 3D complex well trajectories. Specifically, key performance factors were measured enabling quantitative and qualitative statements to be made of drilling performance with the two technologies. The experience gained provides an insight to where it is appropriate to use this new technology and demonstrates the applications for which this technology can provide significant technical and economic advantages.
Underbalanced Drilling in High-Loss Formation Achieved Great Success – A Field Case Study
Authors: Luo Shiying , Hong Ruyu , Meng Yingfeng , Zhang Liehui , Li Yun , Qin Changqing
Published: December 2007

This paper describes the execution of Well Xian-2 using underbalanced drilling technique. At first, new equipment was specially designed for the well, including a liquid/gas separator and a new manifold. Then, the design of wellhead, drillstring, casing, gas injection program, bit selection, well completion and base drilling fluid used in the well are discussed. Besides, operation of UBD in the well is summarized in the paper. Finally, it is concluded that: UBD technique can minimize loss of drilling fluid into formation and increase productivity. As a whole it makes money, though the drilling cost is increased compared with conventional drilling. Simulation for underbalanced drilling plays an important role in optimization of the drilling parameters, which is dictated by actual reservoir inflow performance and well conditions.
A New and Practical Method for Fracture Design and Optimization
Authors: Richardson Michael
Published: December 2007

There is a very long and continuously expanding list of considerations in the process of designing and optimizing fracture stimulation treatments. As a result, there exists today an equally long and varied list of recommended design and optimization procedures for fracture stimulation. However, for each of these methods, the key parameters that ultimately govern the production response after fracture stimulation remain effective fracture length and effective fracture conductivity. This paper presents a simple and easily applied fracture stimulation design and optimization procedure that centers on these two vital parameters. The analysis includes adjustments to fracture conductivity for closure pressure, temperature, embedment, gel damage, non-Darcy turbulent flow, and non-Darcy multi-phase flow. A methodology is presented that optimizes fracture stimulation design for any reservoir type and can be readily applied by practicing stimulation engineers.
Aqueous Polymers for Treating Clays in Oil and Gas
Authors: McLaughlin H.C. , Elphingstone E.A. , Hall Bobby
Published: December 2007

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

Protection of water sensitive formations Protection of water sensitive formations is a serious problem in the production of hydrocarbons. Water sensitivity is usually the result of fines migrating which is triggered by introduction of foreign water. The migrating fines tend to lodge in constrictions in the formation flow channels where they severely reduce production. Water sensitivity can be simple clay swelling, but fines migration causes more permanent damage. However, swelling of clays in fines is an important mechanism for dislodging fines and starting the migration.

The sodium clays are the important form of swelling or dispersing clays. Since sodium ion is easily replaced by others a successful method of helping to prevent swelling and migration is to treat the clays with potassium, calcium, ammonium or hydrogen ions. With these ions the clays are relatively inactive if not quiescent. However, this is temporary protection because sodium ion from formation water protection because sodium ion from formation water quickly counter replaces the non-swelling ions and the clay returns to the swelling or dispersing form.

A new series of certain polymer materials has proved to be effective in treating water sensitive formations. These polymers adsorb tenaciously to surfaces of clay minerals and other formation fines, helping to prevent clays from swelling and fines from migrating should foreign water be introduced into the formation. The polymers win easily in competition with other simple ions (such as ammonium, calcium or potassium) for being deposited on clay surfaces. Furthermore, once deposited on clay surfaces, the polymers are not easily replaced by exchange with other ions. Subsequent acidizing treatments cause no detectable harm to the ability of the polymers to protect the clay. protect the clay. Laboratory test data with sand packs and cores are presented and annotated. The encouraging results of these tests are supported by the results of fracturing treatments, acidizing treatments, and other operations, which are tabulated and discussed.

Introduction

Many oil and/or gas producing formations contain clays, clay minerals, silica fines, and other fines.
Downhole Video: A Cost/Benefit Analysis
Authors: Tague J. R. , Hollman G. F.
Published: December 2007

In the past few years, downhole video has emerged as a viable and cost-effective means for analyzing various wellbore problems. Despite this, numerous misconceptions concerning the cost, application, and complexity remain. In an effort to provide insight into the proper application and selection of this unique tool, the results of over 30 downhole video logs conducted by Chevron in the West Coalinga field will be presented and discussed. Examples will include images obtained of damaged liners, casing holes, and corrosion problems, as well as their application to remedial well work. Other examples will include images of the in-situ producing environment, in particular, the ability of downhole video to image fluid entry and the impact of various wellbore plugging agents including scale and organic precipitation. Finally, the total cost of running a video log and the steps necessary to prepare a well will be compared to more traditional means of logging. Overall, this paper should provide valuable insight for anyone considering the use of downhole video.
Did Checkerboard Steamflooding Work at Kern River?
Authors: Harris Dan E. , Sanford Steven J.
Published: December 2007

A checkerboard-style (Fig. 1) steamflood was initiated on the "MC2" lease of the Kern River field in 1991. We recently evaluated the project to see how it fared and to identify development opportunities.

Even though we overinjected steam, the checkerboard steamflood was mostly unsuccessful because steam did not migrate across pattern boundaries. We suspect that heat was escaping via slotted liners.

We found unswept oil from time-lapse temperature-observation-well (TOW) data and from pulsed-neutron-capture (PNC) logs. We recompleted injectors to steamflood previously unsteamed zones. Downward-conductive heating also enabled more oil to be produced. The oil production quickly increased as a result of this work.
More Than 12 Years of Experience with a Successful Conformance-Control Polymer Gel Technology
Authors: Sydansk R.D. , Southwell G.P.
Published: December 2007

In this paper, we discuss and describe our extensive exper-ience with the widely applied and quite successful Cr(III)-carboxylate/acrylamide-polymer (CC/AP) gel technology for use in oilfield conformance-control, sweep-improvement, and fluid-shutoff treatments, along with briefly reviewing the gel technology's development. Chromic triacetate is the often-preferred chemical crosslinking agent used in conjunction with this polymer-gel technology. The CC/AP gel technology, which was conceived in late 1984, is characterized as having a robust gel chemistry and as being highly insensitive to petroleum reservoir environments and interferences. This gel technology has been employed in over 1,400 conformance-control treatments worldwide. Highlights of illustrative field applications and results involving the CC/AP conformance-control gel technology are presented. An overview of what a decade-plus of experience in developing and applying the CC/AP gel technology has taught us is discussed. This includes discussion of: classifying and distinguishing conformance problems and treatments, attributes of good candidate wells and well patterns for gel conformance-control treatments, requirements that must be met in candidate wells and well patterns in order to achieve success, gel treatment elements that must be successfully implemented in order to achieve success, guidelines where conformance polymer-gel treatments are most successfully applied, risks and pitfalls of gel conformance treatments, and quality control issues.

Introduction

The development and application of effective conformance-control treatments have been, until somewhat recently, elusive goals within the oil industry. Broadly speaking, conformance-control treatments include both treatments to improve volumetric sweep efficiency during oil-recovery flooding operations and treatments to reduce excessive and unproductive co-production with oil of such fluids as water and gas. That is, the co-production of other fluids that compete with the production of oil. Conformance-control treatments have at times been referred to, in an overly narrow fashion, as profile-modification treatments. Polymer gels of conformance treatments act as permeability-reducing agents and, as such, act as blocking and plugging agents. The gels of such treatments operate by reducing the fluid-flow capacity within the treated portion of the reservoir.
Experimental Study of Surfactant Alkaline Steam Flood Through Vertical Wells
Authors: Shedid Ali Shedid , El Abbas A. Abbas
Published: December 2007

Continued research and field application of steam flooding have confirmed an early conclusion that the process is a powerful method for recovering heavy and intermediate gravity crude oils. This experimental study investigates the feasibility of using low concentrated solution of alkaline or surfactant as an additive to steam flooding for water flooded reservoirs. This research is also designed to search for optimization the process of steam flood through recovering additional oil via using a steam with low concentration of alkaline-surfactant mixture. This process is designed as surfactant alkaline steam flood. To achieve these goals, four flow experiments are conducted as follows: (1) conventional steam flood (SF) (2) surfactant steam flood (SSF) (3) alkaline steam flood (ASF) and (4) low concentrated surfactant alkaline steam flood (SASF).

The results of this study confirmed using steam flooding for a substantial improvement of oil recovery. Using low concentrated alkaline into steam drive recovered additional oil than conventional steam flooding. Mixing steam flooding with surfactant improved oil recovery than either conventional steam drive or alkaline steam flood. The proposed technique of surfactant alkaline steam flood (SASF) significantly enhanced oil recovery.

A comparison of the obtained results of the four undertaken experiments results in two major conclusions, which are (1) addition of 3 % wt. of surfactant or alkaline into steam drive improves its performance and consequently recovers additional oil than conventional steam flood, and (2) using low concentrated surfactant alkaline (1.5% wt. for both) into steam flood produces the highest oil recovery.

The results of this study have validated the proposed technique of surfactant alkaline steam flooding. Furthermore, this technique is expected to have a significant impact to attain potential oil recovery, if applied in current projects of conventional steam flood and/or water flooded reservoirs.
Confinement of Wastes Injected Below Thawed Permafrost: A 12 Year Update from the North Slope of Alaska
Authors: Weingarten Jean S. , Bill Michael L. , Andrews Donald E.
Published: December 2007

The main North Slope Class I industrial waste disposal facility has injected 12 million barrels into a permeable formation just beneath the permafrost at 2000 feet. Initial concerns about fluid confinement were addressed by extensive field testing. This testing, coupled with the absence of underground sources of drinking water, allowed injection pressures to be authorized above the fracture gradient - an unusual operating condition.

Re-permitting the facility in 1999 required an evaluation of permafrost thermal response to the injection of warm fluids and determination of potential impacts on waste confinement. This was accomplished using temperature logging after a one week shut-in period and by thermal modeling. At issue was whether the temperature log profiles could be explained by conductive heat transfer or whether they indicated upward fluid movement out of the injection zone. The evaluation was accomplished by coupling a radial thermal model with a onedimensional vertical conduction model. This combination could better predict the temperature profile adjacent to the injection interval because vertical heat transfer is dominant just above the storage reservoir.

Very good agreement was obtained between field measurements and the model results, indicating there was no fluid moving upward through the confining zone. With this "history match" as a basis, the model was used to predict future temperature changes and thaw bulb growth throughout the permafrost interval.
Interwell Seismic for Reservoir Characterization and Monitoring
Authors: Justice J. H. , Woerpel J. C. , Watts G. P. , Waddell W.
Published: December 2007

The U.S. Department of Energy Class II Oil Program was designed to encourage evaluation of new technologies which might improve production in marginal shallow-shelf carbonate reservoirs. One of the largest of the approved programs has been underway in the Welch field, located in the Permian Basin of west Texas for several years. In the first phase of the program, a wide variety of data was acquired, including 3-D seismic, log and core data, and one of the largest interwell seismic baseline programs to be carried out at that time. The purpose of the interwell seismic program was twofold. First, there was interest in using the baseline survey data itself to evaluate its use for reservoir description and characterization (simulation). The second objective was to acquire subsequent monitor surveys, after CO2 injection had begun, in order to map the actual location and movement of the CO2 through the reservoir, as the program progressed.

The first phase of the project is now complete, and the first round of monitor surveys has been acquired in the second phase of the program. Based on comparison of the baseline surveys and the first monitor surveys, and using prior petrophysical work as a basis for interpretation of the results, the injected CO2 appears to be exhibiting a strongly preferential flow direction oriented toward the east/southeast.
Using Alternative Sources of Oilwell Cement
Authors: Hibbeler Jeff , Rae Phil , Gilmore Todd , Weber Lawrence
Published: December 2007

A survey of cement manufacturers in the Asia Pacific Region revealed that only five companies produce a certified API Class G cement. Because of this, certain countries have been forced to import cement and in many cases ship it great distances. In some situations, API Class G cement can cost three times more than local construction cement. While the authors believe that the API Monogram is an excellent benchmark for oilwell cement, the question is – is it necessary to preclude good local cements from use simply because they are not certified. After all, the key issues for oilwell cement are predictability and performance, not certification In the absence of local API Class G cement, the authors propose two ways to use local cement in oilwell applications. First, work with existing construction cement companies to develop cements that consistently meet specifications of the desired API Class and use it in the field. Second, when and where it is applicable, use construction cement for oilwell cementing. The authors are implementing both techniques successfully in parts of South East Asia.

This paper presents historical and technical background as well as laboratory data to support the use of local cements as an alternative to imported API Class G cement. Also, presented are several case studies on the use of local cement in oilwell applications as a means to save drilling costs.
Reducing Well Costs by Optimizing Drilling Including Hard/Abrasive Igneous Rock Section Offshore Vietnam
Authors: Salleh Sahabudin , Eckstrom Darren
Published: December 2007

Bit optimization played a key role in a recent drilling program by an oil company in its Pilot Production Drilling campaign in the Ruby Field Offshore Vietnam. Advancements in roller-cone and PDC bit technology improved performance significantly. These advancements enabled the operator to save time on the 10 well plus 2-workover project and come in under budget. This paper documents the time savings and the development of the crucial roller cone bit technology.
Matrix Acidizing of Water Injectors in a Sandstone Field in Saudi Arabia: A Case Study
Authors: Al-Anazi H. A. , Nasr-El-Din H. A. , Hashem M. K. , Hopkins J. A.
Published: December 2007

The aims of this study were to design a cost-effective stimulation treatment to remove formation damage from water injectors in a recently developed sandstone field in Saudi Arabia and enhance well injectivity, while maintaining formation integrity. This paper examines the design of the treatment, field monitoring, and analysis of acid returns. Core flow experiments were performed to screen various acid formulations, and evaluate acid additives.

The designed treatment was applied on several water injectors. Acid returns were analyzed to evaluate the effectiveness of each treatment. It was found that a preflush of 5wt% NH4Cl solution was effective in displacing potassium and sodium ions from feldspars and clay minerals compared to a preflush that contained hydrochloric acid only. A multi-stage treatment was designed to remove formation damage encountered in several water injectors in this field. The treatment significantly improved the injectivity index of the treated wells.
Design and Optimization for Sucker Rod Pumping System in Deviated Wells
Authors: Mo Y. , Xu J.
Published: December 2007

Commonly used methods for design and analysis of a rod pumping installation assumed a vertical well and ignored the well curvature effect, rod/tubing drag forces and fluid dynamics. These methods could cause substantial errors if they are used to diagnose and analyze the rod pumping system in the deviated wells. This paper presents a new and simplified model to design and evaluate the performance of rod pumping system. Using a 3D quasi-static model involving all the equilibrium equations and deflection equations, the rod loads displacements and stresses for each element are solved recursively. The lateral displacement of the rod is also considered in the model. The possible contact between the rod and tubing is estimated if the rod is supported at certain places, for example, where a centralizer is placed. Taking into account the well geometry, the rod centralizer effect, the fluid viscous effect, the Coulomb friction between rod and tubing, and all the components in the system, the model provides a useful and simple method to design the rod strings and spacing of the rod centralizers, to select the pumping mode for optimization of the system, and to evaluate the performance of a existing pumping system. An efficient computer code is developed. Finally, good agreement is indicated between the results and the actual measured data.
An Independent Operators' Challenge: Balancing Technology, Manpower and Capital
Authors: Eson Rod L.
Published: December 2007

One thing has remained constant in the petroleum industry for the past fifty plus years is change. It is this ever changing landscape of the industry, which brings the biggest challenges, especially to independent operators. The petroleum industry is one of the most capital intensive industries in the world today. However, it does not matter how much money a company has if it does not have the right people to invest those dollars wisely. The third leg of the stool, to use an already overused analogy, is technology. We have seen giant strides made in 3D seismic, extended reach drilling, measurement and logging while drilling, multilateral wells, production surveillance systems and on and on. Even with the brightest people and a pot full of money, a company will soon loose it competitiveness if it does not stay up on the latest technological changes in the industry.

For nearly all independent operators capital is a scarce commodity. Capital is typically obtained through debt from banks or institutional investors or through equity by selling a part of the company through private or public placements. These capital dollars are used to secure the manpower and technology required to acquire properties, drill wells, and complete exploratory plays and a host of other things. If this is done with debt, the operator has repayment obligations, which eats into the capital. If this is done with equity, the growth of the company is shared with others. Each independent operator must look inside to see what type of company they are and what they want to be in the future. They must set a strategy for getting there and then balance the technology, manpower and capital available to them throughout the process.
Precise Fracture Initiation Using Dynamic Fluid Movement Allows Effective Fracture Development in Deviated Wellbores
Authors: Eberhard Michael J. , Surjaatmadja Jim , Peterson Ellis M. , Lockman Russell R. , Grundmann Steven R.
Published: December 2007

In deviated wellbores with long perforated intervals, conventional fracture initiation with wellbore pressurization often creates multiple fracture initiations, resulting in severe fracture tortuosity. When this happens, treatments are generally plagued with high injection pressures, low injection rates and, quite often, early screenouts.

One solution to the problem of multiple fractures is to use the fluid’s own dynamic movement to divert flow to a specific point. This method accurately positions and directs fracture initiation. With proper planning, a single fracture can be initiated and proppant can be easily placed without tortuosity effects.

This paper discusses the use of the dynamic fluid movement treatment in a well positioned on an incline through the pay section. Premature screenout had occurred when proppant first entered the formation on a previous treatment attempt, and fracture modeling indicated that multiple fractures were the apparent cause of the screenout. When the dynamic fluid movement method was used on a subsequent treatment, a fracture was initiated properly, and a large proppant treatment was placed successfully.
The Modelling of Advanced "Intelligent" Well – An Application
Authors: Yu S. , Davies D. R. , Sherrard D. W.
Published: December 2007

"Advanced wells" will find a wider application within the oil and gas production industry once their ability to improve project economics is more widely known. Further, the nature of the industry is such that the application of "Advanced wells" has to be justified on a case by case basis. Actual case histories will only become available very slowly since the projected lifetimes of such wells is normally at least 5 to 10 years. This process of industry acceptance of advanced wells can be speeded up by the approach presented in Reference [1] – developing confidence in the ability to model advanced wells by quantifying their economic benefit with industry proven software by the development and application of an accepted well modeling strategy.

In this paper, a simplified simulation model of a typical North Sea field case is used to illustrate the advanced well modeling methodology by quantifying the benefits of installing an "Intelligent" completion. Several "Intelligent" completions have been modeled in order to obtain an optimum production performance. These range from a simple Inflow Control Valve (ICV) completion in a slanted well to a multi-branch completion with ICVs and installation of down-hole water/gas separators.

We have been able to show that correct advanced "intelligent" well design can accelerate oil production and maximize oil recovery. The identified "intelligent" well completion and production policy was robust since it still maximized the project economic value for a range of typical geological and reservoir uncertainties. Simple economics indicated a pay back of 7-11 times (on a NPV basis) from the implementation of such an advanced well.
Expandable Tubulars: Field Examples of Application in Well Construction and Remediation
Authors: Daigle Chan L. , Campo Donald B. , Naquin Carey J. , Cardenas Rudy , Ring Lev M. , York Patrick L.
Published: December 2007

As the oil and gas industry has matured, three broad-reaching and long-standing issues that affect virtually every well have assumed heightened importance: conservation of hole size, hydraulic isolation of selected zones, and maximization of well life. All of these issues involve one of the industry’s most fundamental technologies, wellbore tubulars. Until recently, resolving these issues with conventional tubular technology was becoming ever more difficult, especially in deep-drilling and extended-reach applications, in wells utilizing liner hangers, and in aging wells containing deteriorating casing. A revolutionary new technology—expandable tubulars—has recently been introduced and has successfully addressed these issues in commercial applications.

The basic concept underlying expandable-tubular technology is simple: a mechanical expansion device, known as an expansion cone or mandrel, is propagated through downhole tubulars utilizing hydraulic pressure. The progress of the cone expands the tubulars to the desired internal and external diameters in a plastic deformation process known as cold drawing.

In drilling applications, a specially-designed liner hanger utilizing the new expandable-tubular technology conserves hole size by eliminating the need for a conventional liner hanger/liner hanger packer, and provides a superior pressure seal compared to the old technology. In cased wells, expandable casing is cladded to existing casing, either to repair or strengthen the existing casing, with minimal decrease in wellbore inside diameter (ID) and flow potential. Expandable tubular solutions have been successfully installed in the Gulf of Mexico, in U.S. inland wells, as well as in large-scale field trials.

This paper briefly describes the technical concepts upon which expandable tubulars are based and gives an overview of expandable-tubular applications. The paper then focuses on the most recent field installations, including systems installed during the first quarter of 2000. Discussions of field examples will contain customer objectives, job design, installation procedures, ultimate results and best practices learned.
Design of a Riser Recoil Control System and Validation Through Full-Scale Testing
Authors: Stahl M. J. , Hock C. J.
Published: December 2007

This paper discusses the development of a riser recoil control system for a state-of-the-art drilling vessel. This control system, designed using computer simulation, is capable of controlling riser recoil in water depths of 3,000 to 10,000 ft and a wide range of tensions. Two full-scale tests occurred in 6600 ft of water in the Gulf of Mexico. Data from the first test, using 400 kips overpull, showed that only minor adjustments to the computer program were required. A second test, with 800 kips of overpull and only 20 ft of telescopic joint stroke occurred two days later. We believe that a riser disconnect test under these conditions is unprecedented. Data from both tests demonstrated that the system functions as intended and that the analysis method is valid.

This work shows that computer simulation is a reliable method of developing robust solutions for riser recoil control. Similar analysis is also useful in simulating existing systems to determine operating limits and investigate potential enhancements.
Use of Java™ Technology for Web-Based Reservoir Engineering Applications
Authors: Fenwick Darryl H.
Published: December 2007

The increasing power, speed, and ease-of-use of the Internet has challenged industries to develop new methods for doing business. This paper focuses on the petroleum industry and how it can use new emerging technologies in an innovative manner to reduce cost and increase productivity. The paper first describes briefly the Java tools available with Java 2 platform and reviews how industries have used them to redefine their business models. The paper then focuses on an actual web-based reservoir engineering application. A web site is presented that provides several reservoir engineering applications (material balance equations, decline curve analysis, geomodeling packages), freely available to the public. The web site demonstrates concretely how emerging Internet technology can make available both simple and complex reservoir engineering applications using a simple web browser. A vision of the future of petroleum engineering software is presented, where every engineer with a browser and internet connection has access to a suite of petroleum engineering software products without need for software licenses, installations, or software updates.
Design and Analysis of a Multiphase Turbine for Compact Gas-Liquid Separation
Authors: Rawlins C. H. , Ross G. D.
Published: December 2007

The Rotary Separator Turbine (RST) utilizes unique technology to provide compact separation of oil and gas, while recovering energy wasted in conventional pressure let-down operations. The technology has been utilized for industrial refrigeration and geothermal applications since the early 1980’s, and has recently finished field evaluation and assessment on a deepwater tension leg platform in the Gulf of Mexico. The focus of this paper is on the operating principles and mechanisms of multiphase turbine technology and design parameters for installation as a separation or power generation system in new developments or in debottlenecking applications. Operational experience pertaining to separation efficiency, mechanical reliability, and power output in a live fluid environment will be highlighted.
Market Segmentation and Pricing Strategies in the North American Natural Gas Market
Authors: Garcia Percy , Vredenburg Harrie
Published: December 2007

This paper analyzes the marketing strategies followed by Canadian companies operating in the North American natural gas markets. It focuses on two elements of the marketing mix: (a) market segmentation and (b) pricing. The highly competitive natural gas markets of North America, strengthened by the deregulation process, the restructuring of electric utility industries, the advance in technological communications, and the global growing concerns on environmental issues, make market segmentation and pricing key elements in setting marketing strategies. The main findings of this research are: (a) the market segmentation is highly dependent on the availability of pipeline distribution and cost of transportation of gas; (b) decisions on market segmentation regarding types of customers are highly dependent on the highest netback that can be obtained; (c) pricing in the natural gas market of North America is highly affected by the availability of distribution pipelines, cost of transportation, period of contract with buyer companies and by the use of alternative energy sources by end-users; and (d) there is a direct relationship between geographical market segmentation and pricing. The factor that links these two variables is the availability of pipelines to move the gas to the markets.
Integrated Development Plan for a Naturally-Fractured Gas-Bearing Granite Reservoir
Authors: Hazlett W. G. , Snow P. W. , Gonten W. D. Von , Glasgow W. M. , Banks R. J. , Duncan C. S.
Published: December 2007

This paper describes the characteristics of and development plans for the PY-1 concession, a gas reservoir contained in a naturally-fractured granite formation. Over a several-year period, exploration and delineation wells were drilled offshore India. The paper covers all aspects of the integrated geoscience/engineering development study, including seismic, core and fracture analyses, well logging, well testing, and reservoir simulation. In addition, we include the offshore facilities, pipeline and onshore compression plans. The development plan was prepared by a team of engineers and geoscientists made up of both operating company personnel and contract and consulting personnel. The result of the study is a development plan for a granite reservoir. We conclude that highly-fractured granite formations should not be overlooked as potential reservoirs. This granite reservoir should provide a steady gas supply to any one of several commercial manufacturing facilities planned for the area.