bluuebunny/crossref_metadata_2025 huggingface dataset:
Metal-to-Metal Sealing Technology: Bridging the Gap Between Conventional and High-Expansion Zonal Isolation Applications
Authors: Garfield Garry , Mackenzie Gordon
Published: December 2007

Metal-to-metal sealing technology is an innovative type of medium to high expansion seal that uses compliant metal as a pressure barrier and incorporates an extraordinary seal performance envelope that cannot be achieved by conventional elastomeric seals. Zonal isolation tools, including bridge plugs and straddle systems, using metal-to-metal sealing technology in place of conventional elastomers may radically challenge existing engineering philosophies by providing a pressure sealing system capable of exceeding the limitations of other existing sealing technologies and eliminating many traditional elastomeric failure modes.

The metal-to-metal seal has the potential to change the way downhole equipment provides pressure integrity during pressure pumping operations by utilizing a controlled application of load to expand the metal seal to achieve a fully formed pressure barrier which allows for the metal-to-metal seal in bores of up to 160% of the original seal diameter.

In the well servicing market, recent applications of the metal-to-metal seal and the latest lab testing have suggested the prospective of the technology for products for not only the conventional markets but also in the hostile HPHT arena. Metal-to-metal sealing technology could make well suspensions and intervention possible in hostile HPHT wells that were previously deemed inoperable by the complete removal of elastomers from the design. Demonstrating versatility in applications on land to deepwater locations, metal-to-metal sealing devices can be easily deployed on slickline, electric wireline, coiled tubing, or drill pipe to save operator rig time in areas where cost savings are critical.

Case studies of the high performance characteristics of the metal-to-metal sealing technology in terms of design, testing, and implementation will recognize its alignment in regards to conventional elastomeric sealing technologies as well as high-expansion inflatable technology.
Achievements of Smart Well Operations: Completion Case Studies for Hydro
Authors: Raw I. , Tenold E.
Published: December 2007

Hydro and Schlumberger have worked closely since 1998 to develop and install intelligent completions with increasing functionality in the Norwegian North Sea. This paper will provide and discuss several case histories in the region. These include:

Installation of a natural gas lift application to enhance oil production at Troll field, which used a single control line to surface to operate a six-position gas lift valve to regulate flow from the gas cap. Installation of multizone monobore completions in the Oseberg field to offset production decline, in which several highly deviated and long-reach wells were successfully completed in two to three zones with established zonal isolation and flow control.

Other case histories include the creation of innovative intelligent completions for multilateral wells with lateral flow control and natural gas lift with the gas cap perforated by tubing-conveyed perforating guns side-mounted on the production tubing.

Among the observations made is that implementation of reliable pressure, temperature, and flow monitoring in the industry has not kept pace with the complexity of the flow control capability. The ongoing challenge is to create intelligent wells with reliable monitoring technologies to fully capitalize on the benefits and opportunities of zonal flow control. Innovative completion designs and state-of-the-art reservoir monitoring and control technologies are critical to intelligent well development.
An Imperative Workflow for Modeling of Naturally Fractured Reservoirs on Different Scales
Authors: Heinemann Gabor F. , Bashiri Gholamreza , Harrer Andreas W. , Keramati R. Mohamad , Mittermeir George M.
Published: December 2007

Most of the recently discovered giant oil reservoirs are naturally fractured which necessitate dealing with high level of complexity during development. Consequently, negotiation between field owners (government, National Oil Company (NOC)) and the potential International Operating Companies (IOC) are time consuming and may lead to unnecessary loss of business opportunities. The IOC's objective is to maximize the profit using their capital and know how anywhere in the world, whereas the NOC's goal is to generate as much value as possible from their assets. The different key objectives lead compulsorily to different reservoir evaluation workflows.

To meet the IOC's needs the BP's Top Down Reservoir Modeling (TDRM) approach may be most suitable, where the most simple appropriate models are used. Details and complexity are only added, if the previous investigations show favorable economics; i.e. in the TDRM approach unprofitable projects - in IOC's point of view - are not analyzed in detail.

TDRM is not applicable for NOC's offering oil fields in bidding process, requiring deepest possible understanding of the reservoir's geology, physics, production potential and ultimate recovery as basis for their negotiations.

The workflow presented herein aims to achieve the owner's (NOC) objectives in the most efficient way; i.e. asses and minimize uncertainty, reduce project turnaround time and finally end up with a reliable and consistent full field model. The approach is neither "top down" nor "bottom up" but it is rather a "MultiLevel Reservoir Modeling" (MLRM), performing investigations in parallel on different scales in an iterative loop. MLRM requires consistent high sophisticated simulation tools with special options for gridding, upscaling/downscaling and well management.

The modeling approach was developed and applied to giant, natural fractured, dual porosity carbonate reservoirs with sparse data and hardly existing production history. The reservoirs have a large lateral extend with varying oil column thickness and bottom water drive. The applicability of the approach to other reservoir types is not topic of this paper.
Enabling Workover Applications With Coiled-Tubing-Deployed Inflatable Packers
Authors: Carrillo J. , Paz A. , Franco E. , Nájera R. , Perez J. , Cabrera J. , Zamarron A.
Published: December 2007

Cantarell field produces a significant portion of the total oil production of PEMEX. Over the past few years, Cantarell oil production has been declining, mainly because of the maturity of the field. Sustaining oil production at current levels is a constant challenge for PEMEX, which is also attempting to increase exploration. One of the main challenges involves an increase in water production, which has led to wells being temporarily shut in until a workover rig becomes available. This waiting time could be years. Meanwhile, PEMEX is investigating alternative solutions to optimize rig utilization and offshore rigless workover options.

Recently, coiled-tubing-conveyed inflatable packers have become a key enabler when performing workover operations while the production tubing remains in place, which enhances timely and cost-effective intervention solutions. Through-tubing inflatable packers have successfully isolated zones during water-control treatments, cementing operations through coiled tubing (CT), and permanent zonal abandonment, thus enabling the operator to perforate the upper oil-bearing zones. The use of through-tubing inflatable packers for zonal isolation is now featured in the rigless workover plan for several wells, which is expected to deliver a significant increase in oil production.

This paper examines these recent applications of through-tubing inflatable packers in the region and presents the relevant well conditions and the criteria used for selection. It provides case histories and best practices from several through-tubing applications. Recommendations for job design, auxiliary equipment, and personnel competency are thoroughly discussed.
First Subrigfloor HWO Intervention System for a Floating Vessel
Authors: Pollock Tim , Armagost Ken , Andersen David , Oser Michael , Besly Jason
Published: December 2007

Current capabilities with coiled tubing and slickline are insufficient to provide complete well intervention support to deep, high-pressure wells drilled from a floating vessel in a deepwater Gulf of Mexico (GOM) field. These intervention technologies limit the allowable departure of proposed wells to 8,500 ft and often restrict intervention scope to "dead well" operations.

A hydraulic workover (HWO) system is being developed to support a deepwater GOM field. The system will be located under the rig floor with heave compensation provided by the rig's riser tensioning system. HWO control will be achieved using a remote panel and operations will be observed from the driller's cabin on closed-circuit television (CCTV). To keep the stack-up height as short as possible, the surface pressure control equipment (PCE) will utilize special unitized body valves. The PCE will be stored on a purpose-built fixture where it can be pressure and function tested prior to rig up. The surface and subsea PCE will include shearing and sealing capability for the largest diameter pipe to be used.

The HWO solution provides a high-strength conveyance method to intervene and operate under pressure from a floating vessel in deep, high-pressure reservoirs. The customized HWO extends intervention capabilities to a departure of 15,000 ft (28,800 ft MD) under 8,800-psi wellhead pressure.

The HWO provides features that enhance personnel safety and economic efficiency. The advantages of a sub-floor HWO include: (1) improved safety by removing personnel from an elevated workbasket exposed to pressure and erratic movement, (2) more efficient operation through use of the rig's regular hoisting equipment, (3) elimination of the need to pull production tubing when extending existing wells, and (4) complete reservoir accessability without the need for satellite wells.
4th-Generation Coiled-Tubing Manufacturing Technology
Authors: DuBois Jon D. , Atwood Martin P.
Published: December 2007

Innovative new technologies in coiled tubing (CT) manufacturing will present new opportunities in the industry. The new technology represents a 4th generation CT manufacturing process known as the Continuous Variable Reduction (CVR) process. A brief overview of current manufacturing technology will be presented followed by key elements of the new CVR 4th generation manufacturing technology. Then, the advantages of the CVR technology will be presented along with examples of new products to come from CVR.

Continuous Variable Reduction (CVR) technology has application in the manufacture of variable outside diameter, variable wall thickness, and variable strength all within the same CT string. There is also application in the manufacturing of small diameter, heavy-wall, high-pressure strings. The CVR process will produce CT without internal weld beads.

The significance of the ability to manufacture coiled tubing with variable OD, variable wall thickness, and varying strength levels without the typical ring or "butt" welds now required to join multiple diameters represents a significant advance in coiled tubing manufacturing technology.
Use of Self-Lubricated Plungers in Sucker Rod Pumps Producing Oil From Wells in North Santa Cruz
Authors: Bertomeu F. , Rodrigues N. , Dottore E. J.
Published: December 2007

Every standard down hole sucker rod pump slips fluid between the plunger and the barrel. This is necessary because they all look to the formation fluid for lubrication to enable the plunger to move up and down in the barrel. Slipping fluids causes several problems. In addition to poor pump efficiencies, if there are solids in the formation fluid, such as formation sand, frac sand, iron sulfide and scale, the pump may experience premature failure. The solids cut the plunger and the barrel increasing the clearance between them, further reducing the pump efficiency. Even more, in certain conditions, the plunger may stick and not pump at all.

Self lubricated plungers are equipped with seals on each end. The seals perform two vital functions. They trap a Teflon based liquid lubricant, and they prevent the formation fluid and whatever solids may be in the fluid from getting between the plunger and barrel. Consequently, the pump is self lubricated with the barrel coated with its own lubricant on every up and down stroke. In addition, formation fluid is not allowed to travel between the plunger and barrel, thereby avoiding wear, pump sticking and accumulation of deposits.

The purpose of this paper is to present to oil producers the advantages experienced with sucker rod pumps equipped with self lubricated plungers in the oilfields of "Pico Truncado", "El Cordón" and "Cañadón León", all located in the north of Santa Cruz, Argentina.
Initial UBD-Reservoir Candidate Screening Prevents Applying the Technology to the Wrong Reservoirs: Case Study
Authors: Babajan Salar , Qutob Hani
Published: December 2007

The Petroleum Development of Oman, PDO has been considering adapting new technologies to ensure that strategic resources are optimally explored, developed and produced during the life cycle of their fields. Among the various options available to achieve these objectives, Underbalanced Drilling technology is considered to evaluatthe benefits over traditional drilling and completion methodologies in terms of reservoir performance.

Accordingly, an Underbalanced Drilling reservoir candidate screening process was initiated to examine the suitability of the technology for seven gas reservoirs in PDO.

The screening process began by taking basic reservoir and drilling data and processing it through expert system software. The software rated the candidacy of the reservoir to help determine the likelihood of achieving success with underbalanced vs overbalanced drilling and completion techniques, to identify the best potential underbalanced candidates from the given portfolio and proceed with a detailed analysis.

The expert system score for underbalanced candidacy is calculated by considering different modules. Each module includes a comparison of the key differentiators between overbalanced and UB techniques that impact the UB candidacy of a reservoir. To make these comparisons, the expert system assumes a well is drilled overbalancedand assesses the potential effect on reservoir performance and then estimates the potential benefit of underbalanced drilled wells with minimal damage.

In this paper, the results of the screening process for the gas reservoirs examined are presented and discussed. The study confirmed that candidate selection is a critical first step before initiating any underbalanced drilling project. It also explains why when correct candidates are chosen, UBD significantly improves productivity compared with conventional overbalanced drilling practices.
Phase Behavior Study in the Deep Gas-Condensate Reservoir With Low Permeability
Authors: Qi Zhilin , Liang Baosheng , Deng Ruijian , Du Zhimin , Wang Shouping , Zhao Wei
Published: December 2007

Recently, more and more deep reservoirs are developed due to the appearances of new technologies. Among them, gas-condensate reservoirs, with high temperature, high pressure, and low permeability, account for a high proportion. As a result, not only gaseous formation water is needed to be considered, reservoir deformation and interfacial phenomena should also be included. It is a big challenge for conventional PVT analysis to acquire real phase behavior.

In this paper, we considered the characteristics of reservoir formation and fluids under the conditions of high temperature, high pressure, and low permeability. Then, two models were developed: dew point prediction model for the oil-gas system, and the prediction model for retrograde liquid saturation during the constant volume depletion development. On the basis of hydrocarbon PVT experimental test with rich gaseous formation water, reservoir deformation and interfacial phenomena are further investigated. The models were applied to a deep gas-condensate reservoir with low permeability in Zhongyuan Oilfield, China. The results demonstrated that interfacial phenomena and reservoir deformation not only increased dew point, made the retrograde process earlier, but also aggravated the effects of retrograde condensation.
Closing the Gap Between Reservoir Simulation and Production Optimization
Authors: Awasthi Ankur , Sankaran Sathish , Nikolaou Michael , Saputelli Luigi , Mijares Gerardo
Published: December 2007

The operation of oil and gas fields requires that a multilevel decision hierarchy is used to address field optimization at all timescales. These decisions affect production volumes and costs, not only in their short-term outcomes but also over the life of the field. Depending on the time scale, several models with varying degrees of complexity and detail are typically used to characterize the reservoir (e.g. material balance, full-physics model, and decline curve). However, the strategy to integrate and maintain these separate reservoir models (describing the same field) is often ad hoc and inconsistent.

To make predictions suitable for short-term decisions, proxy-models (e.g. neural networks, response surface) have been proposed. However, these black-box models do not consider the underlying physics of the reservoir phenomena and are limited to the effects captured in the training data set.

In this paper, we build upon our earlier work [1] on integration of full-field strategic models (physics-based) and short range operational models based on the moving-horizon, parametric identification approach for reservoir simulation. A short-range, reduced-order model structure is developed, and the model parameters are obtained from production history data. Because the model structure is motivated by the decomposition of a full-physics model, it is expected to be feasible to extrapolate outside the range of history data. The reduced-order model also increases the computational efficiency and effectiveness in carrying out the simulation objectives. The benefit of the proposed model is to assist in the short-term decision making in production operations. This paper provides a discussion of the methodology for identifying such physics-based parametric models for production operation workflows. It also presents case studies to illustrate the benefits of this method for real time production operations and closed-loop reservoir management.
Utilization of Artificial Neural Networks in the Optimization of History Matching
Authors: Ramgulam Asha , Ertekin Turgay , Flemings Peter B.
Published: December 2007

Artificial neural networks are becoming increasingly popular in the oil and gas industry. In the past, studies have been done on the use of artificial neural networks in reservoir characterization, field development and formation damage prediction, to name a few. The aim of this study is to provide guidelines to successfully develop and train an artificial neural network (ANN) that will predict reservoir properties that can give an improved history match when input into a reservoir simulation model. An ANN was developed to improve the history match with a "small" number of simulation runs for a reservoir that produced oil, gas and water for a period of ten years. Due to a lack of specific protocols for this type of study, the trial and error process was utilized to establish guidelines and suggestions.

The neural network was developed by using an inverse solution method to formulate the training and testing data. Normalization of the data simplified the neural network, improved its effectiveness and enhanced its performance. The feed-forward network with back-propagation and the hyperbolic tangent sigmoid function (tansig) in the hidden layers of the network proved to be most effective in the training/learning process.

Results indicated that functional links and eigenvalues of various system related matrices were effective in the training/learning process. These provided the network with the necessary connections that linked the inputs to the required outputs. It was necessary to input production differences between the historical and simulated performances at specific times to successfully train the network and predict realistic property values for the reservoir. Data structure and production time intervals influenced the training time as well as the accuracy of the predictions. If time intervals were too short, training times were longer, memorization occurred, and the network could not accurately predict the reservoir's properties. Most of the effective functional links that were successful in the training/learning process included relationships between permeability and other factors such as porosity, areas of the regions in the reservoir and the distances from the producer to the boundaries of the reservoir.
Ultraslim Rotary-Steerable System Gives Greater Reservoir Access in Saudi Arabia
Authors: Dhaher Karam , Chia Christopher R. , Al-Amri Khalifah , Bargawi Riyadh Ahmad
Published: December 2007

This paper describes the successful introduction of ultraslim rotary steerable system (US-RSS) drilling in Saudi Arabia. A case study is presented where a 2167ft power water injector redrill lateral was successfully drilled in the reservoir using an US-RSS on 2 3/8"drillpipe in conjunction with ultraslim logging-while-drilling tools, which were used for concurrent high accuracy geosteering. The existing casing design required that the sidetrack had to exit the liner in the reservoir section, since sidetracking higher up was not an option because of the risk of exposing problematic formations and pressurized zones. A number of challenges had to be overcome, including engineering design for sufficient weight transfer to be able to drill and good bit selection, since it would have been impossible to drill the planned section with a motor or conventional drilling assembly.

Each stage of the job was carefully planned in detail and all stakeholders were briefed and contributed to the plan to ensure that all objectives – both drilling and well placement, could be met. The US-RSS was run in hole to drill the lateral, which was drilled with a 3 7/8" bit and concurrently opened up to 4¼". The US-RSS tool performed as planned and produced an overall rate of penetration (ROP) of 28ft per hour in a single run during the geosteering operation. All well objectives were achieved, and the system clearly demonstrated a robust technical solution to the problem.

The US-RSS will enable greater reservoir access, especially in the redevelopment drilling application, and when used in conjunction with ultraslim LWD tools, can also be used to place the well in the best position for optimal additional production. Recovery rates from the field are now expected to be enhanced as a result of this technology, and without the need for drilling further new wells.
An Efficient Response Surface Approach for the Optimization of ASP Flooding Processes: ASP Pilot Project LL-03 Reservoir
Authors: Zerpa Luis E. , Queipo Nestor V. , Pintos Salvador , Tillero Edwin , Alter David
Published: December 2007

The EOR method so called alkaline-surfactant-polymer (ASP) flooding has proved to be effective in reducing the oil residual saturation in laboratory experiments and field projects through the reduction of interfacial tension and mobility ratio between oil and water phases.

Two issues are critical for a successful ASP flooding project: i) addressing issues related to laboratory design such as chemicals selection and concentrations, in order to obtain an optimal ASP formulation, and ii) establishing an optimal injection scheme for the field scale flooding process, that will maximize a given performance measure (e.g., oil recovery efficiency or displacement efficiency), considering a heterogeneous and multiphase petroleum reservoir. This paper presents an efficient solution approach for the latter issue.

The approach is based on the construction of quadratic response surface models (surrogates) of reservoir simulator outputs and three-level D-optimal design of experiments. It allows to effectively and efficiently establish the optimum ASP injection scheme, and was applied to determine the optimal values of injection rates, slug size and initial date for injection of an off-shore ASP pilot project being developed by PDVSA at La Salina Field, LL-03 Miocene reservoir on the eastern coast of Maracaibo Lake, Venezuela. The optimum injection scheme resulted in substantial savings in chemicals used when compared to the laboratory design.
Improved Well and Reservoir Management in Horizontal Wells Using Swelling Elastomers
Authors: Mahrooqi Majid Abdullah , Hinai Ghaliba , Marketz Franz
Published: December 2007

Petroleum Development Oman (PDO) is producing substantial amounts of unwanted water or gas from most of its oil fields. To increase recovery from maturing reservoirs, PDO is developing the capability to detect and shut-off unwanted water and gas. Swelling elastomers have been deployed to segment horizontal wells in combination with surveillance and shut-off technologies. In beam pump wells dual wellheads have enabled logging while pumping.

A key element to achieve improved oil recovery through well and reservoir management in a horizontal well is segmenting the well into different flow units. Swelling Elastomers (SE) are being deployed to enable segmentation. SE tool provides zonal isolation through the swelling of the elastomers when contacting produced water in the wellbore.

In clastic reservoirs the completion philosophy has been changed from drilling minimum functionality wells to wells with closed-annulus completions that allow for surveillance and interventions. Surveillance is done in the drilling phase with under-balanced drilling and other open hole logging measurements. In the work over phase unwanted flow segments have been detected by logging while pumping coupled with greater integration of available reservoir data. Mechanical segment shut-off methods have been used.

To date PDO has segmented more than 100 horizontal wells with swelling elastomers. In more than 20 wells suspected water producing feature were isolated at the initial completion stage and the rest were segmented based on reservoir flow unit characterization. After having proved that SE is delivering value in initial water shut off, the strategy is to prove a viable surveillance technique to identify water entry point in horizontal wells, and to develop several reliable water shut off (WSO) techniques depending on which segment's to be closed and if reversibility is required. To date more than one million barrels of oil have been realized as a result of the initial isolations as well as subsequent water shut offs. This paper is a continuation to the work presented in SPE paper number 91665 and will present case histories of the delivery and management of wells with swelling elastomer in clastic reservoirs in Oman
Implementation of a Shock and Vibration Mitigation Process: Achieving Real-Time Solutions and Savings
Authors: Akinniranye Goke , Weber Amanda , Elsweisy Hesham , Palacio Julio , Poedjono Benny , Goobie Roger
Published: December 2007

Worldwide the costs associated with the exploration and production of oil have increased at a nearly exponential rate. This sharp rise in daily costs has also led to a new urgency from operators to find more reliable and efficient ways of doing business.

Shock and vibration (S&V) are the leading cause of failure for measurements-while-drilling (MWD) and rotary steerable systems (RSS) today. These failures have a major impact on operators and service companies, costing millions of dollars in repairs and hours of rig time.

A wide variety of service companies now offer lateral, axial, and transverse shock measurements, as well as downhole revolution per minute (RPM) readings to better understand downhole dynamics. These measurements in the best of cases offer a reactive method of drilling, and at the worst provide no help in solving the problem or preventing damages to the bottom hole assembly (BHA).

For shock and vibration measurements to be effective, operators and service companies need to work together to create a comprehensive process to include each phase of drilling: planning, execution, and evaluation. A shock and vibration standard combined with increased client awareness and education have allowed a new level of success to be set at the rig site. Now, shock and vibration issues at the rig can be flagged in real-time and monitored remotely from an operations support center (OSC). This communication structure, coupled with pre-job planning and modeling and the capture of post run lessons learned, can be used to offer solutions when problems arise; thus preventing damage to the BHA, reducing rig non productive time (NPT), and improving the rate of penetration (ROP).
Using Decision Analysis to Solve Real Option Valuation Problems: Building a Generalized Approach
Authors: Hahn W. J. , Dyer J. , Brandao L. E.
Published: December 2007

There are several different methodologies for finding the value of assets or projects that have both underlying uncertainty and the managerial flexibility to optimize decision making. This has led to questions about the differences between approaches to these so-called real option valuation problems; the assumptions, mechanics, and applicability of the various methods for different problems.

In this paper, we show that traditional decision analysis methods can provide an intuitive generalized approach to valuing real options. The first characteristic of our approach is a departure from the binomial lattice framework with replicating portfolios that is typically implemented in the discrete-time approach in the Finance literature to a binomial decision tree with risk-neutral probabilities. This gives an equivalent but more intuitive framework for approximating the uncertainty associated with the changes in the value of a project over time. The second characteristic is a methodology for combining uncertainties for a project into a single underlying uncertain variable; the present value of the project itself. This approach provides greater flexibility in modeling of real problems, including the ability to include multiple underlying uncertainties and multiple options with complex payoff characteristics.

We apply this method to an example acquisition valuation problem, showing the specification of project uncertainties, cash flows, and decisions, and demonstrate how solutions can be obtained with commercially available decision tree software.
Economic Capital Optimization for Oil Firms
Authors: Hightower Lee
Published: December 2007

"Economic Capital Optimization" (ECO) provides a comprehensive methodology to improve a firm’s expected long-term growth while reducing its risk. This framework adapts and extends proven economic capital methodologies developed in the financial services industry to address both the similar and unique financial issues facing oil companies.

Economic capital is the capital a firm must maintain to sustain long-term growth by covering short-term and long-term needs or losses. For sustainable growth, a firm must have the capital to support the operations that create economic value, despite anticipated and unforeseen shortfalls in cash flow or changes in business cycles. Insufficient economic capital can disrupt a firm’s operations, destroying value and eventually leading to potential default. Overcapitalization or poor allocation of economic capital can lead to corporate returns and growth that fail to meet investors’ expectations.

Optimizing economic capital requires properly aligning a firm’s capital structure, strategies, capital allocation process and risk management practices to maximize long-term growth. ECO provides a practical framework for examining the interdependencies among these components and for understanding how each impacts the long-term success of the organization.

This paper discusses the concepts behind ECO and its practical application in the oil industry. This paper also will demonstrate how an oil company can improve its expected long-term growth by applying the ECO framework to more effectively allocate economic capital among business units or projects, to adjust its economic capital to meet long-term strategic needs, and to better manage its risks.
Overcoming Environmental Challenges Using Innovative Approach of Dynamic Underbalance Perforating
Authors: Baxter Dennis , McCausland Harold , Wells Brian , Mishra Vinay K. , Behrman Larry
Published: December 2007

This paper discusses the implementation of dynamic underbalance perforating in a subsea development, which helped address environmental concerns related to flaring during perforating. Use of a new perforating system implemented on recently completed wells has resulted in a significant reduction in flaring while maximizing underbalance during gun detonation. The elimination of flaring has also simplified perforating operations, resulting in significant time savings.

The Terra Nova offshore field is located 350 km off the East Coast of Canada. It is a subsea development producing from a multi layered, highly faulted oil reservoir to a Floating, Production, Storage and Offloading vessel (FPSO). The development plan utilizes high productivity producer-injector pairs in the individual fault blocks to optimize recovery. Initially, standard practice was to perforate wells using multiple runs of wireline conveyed guns, up to 6 runs per well. In order to maximize completion efficiency the wells were perforated in an underbalance condition. The underbalance was generated by flowing back and flaring the well at the Mobile Offshore Drilling Unit (MODU) during each wireline run. The net results were multiple flowbacks per well, with diminishing underbalance for each successive perforating run due to flare rate limitations. The multiple flowbacks increased the risk for environmental incidents due to unintentional releases while flaring. Alternative gun deployment methods had been considered but deemed undesirable due to sump limitations and potential for formation damage.

In order to minimize flaring an innovative perforating technique was implemented. This technique generates dynamic underbalance during gun detonation, mitigating the need to flare the well to create underbalance. Fast pressure gauges were run on wells perforated using this method and the data confirmed that dynamic underbalance was achieved. Successful implementation of the dynamic underbalance system has resulted in elimination of flaring related to perforating operations, and has significantly reduced the potential for unintentional environmental releases.
Locating and Repairing Casing Leaks With Tubing in Place—Ultrasonic Logging and Pressure-Activated Sealant Methods
Authors: Johns J. E. , Cary D. N. , Dethlefs J. C. , Ellis B. C. , McConnell M. L. , Schwartz G. L.
Published: December 2007

When operators are faced with issues involving casing leaks, a typical course of action is to pull the tubing and make efforts to identify and locate the source of the leak by logging or other mechanical means. If the leak source can be successfully located, a mechanical method is generally employed to patch the leaking casing. This methodology is time consuming and expensive.

Locating casing leaks with the tubing in place using conventional logging techniques has historically been difficult. Where some tools, such as temperature tools, may provide an indication of an anomaly in annuli, the data may be subjective or the leak may be too small to measure. When active, a leak will produce a spectrum of sonic frequencies that may be either audible, ultrasonic or both. Ultrasonic energy will pass through steel but travels relatively short distances. A tool developed around these principles has been successful in accurately locating casing leaks behind tubing.

Pressure-activated sealants have been used for a number of years to cure a wide variety of leaks in casing, tubing, control lines, and well heads as well as micro-annulus leaks in cement. For the purpose of repairing a casing leak behind tubing, the liquid sealant may be pumped into the annulus and displaced to the leak site. The liquid sealant will not polymerize until it is exposed to the differential pressure through the leak site. Knowing the leak rate, pressure and precise location of the leak aids in the selection of the sealant formulation and deployment method. This helps to reduce overall repair cost as well as increase the probability of a successful repair.

This paper will describe the ultrasonic method of leak detection and the method of curing leaks with pressure activated sealant with tubing in place. Case histories will be presented where these methods were employed to repair casing leaks without removing the tubing.
How to Evaluate the Effect of Mud Cake on Cement Bond Quality of Second Interface?
Authors: Ma Yong , Cui Maorong , Guo Xiaoyang , Shi Qing , Li Li
Published: December 2007

A set of HPHT core filter press and a special manmade core have been designed to simulate the bond quality of second interface of cement job, i.e. the bond status between borehole wall rock contains mud cake and slurry, mud cake has formed on the rock at HPHT conditions. The filter press consists of three parts: heating jacket, HPHT cauldron and core holder, and the center of special manmade core has been drilled a disconnected hole as filtration outlet of drilling fluid. The drilling fluid only can filtrate from the outer wall of the special core to that of inner wall and form mud cake at the outer wall when carrying out filtration experiment of drilling fluid, so this bond status is in agreement with downhole condition. Slurry bond mold has been combined with HPHT core filter press, a novel method for evaluating the bond quality of second interface of cementing has been developed, and the method has been used to measure the shear bond strength between manmade core and slurry.

In order to verify the rationality of the method, it has been applied to evaluate the effects of three drilling fluids on the second interface after mud cake formed on the special core. High flow rate washing before cementing has been simulated to wash manmade core after HPHT filtration experiment. The study shows that the novel method is simple, scientific and rational, better simulates the bond status of cement-formation interface; the mud cake has a pronounced affect on the shear bond strength; this method has high applied value, and develops a good foundation for studying the effect of drilling fluids upon the bond strength of second interface quantitatively; high flow rate washing before cementing is helpful for improving the bond quality of cement to formation.
Drilling Cost Optimization in Iranian Khangiran Gas Field
Authors: Bahari A. , Seyed A. Baradaran
Published: December 2007

Cost optimization, is a procedure, which its final goal is to reduce the cost by making the interfering parameters to the optimum level. In drilling operation, a large amount of saving in time and money will be achieved, by reducing the drilling time, since; some of the costs are time-dependent. Drilling time is reduced by increasing the rate of penetration. Rate of penetration is affected by many parameters such as hydraulics, weight on bit, rotary speed, bit type, mud properties, formation characteristics, etc. In this research, nine wells from Khangiran gas field were selected and by comparing drilling parameters in these wells, a primary optimization by comparison has been performed. Then, secondary optimization using mathematical techniques was applied to make drilling variables to the optimum level and give a computational optimized well. Finally, primary and secondary optimizations were combined together to reduce drilling rate and cost as much as possible.

An optimal well, which can improve drilling time 30 % to 180 % in relation to the wells, drilled and save a considerable amount of drilling cost was designed for Khangiran field after applying optimization techniques.

The significance of this research is to reduce the time and cost for drilling the next wells in Khangiran field. In addition, the same techniques can be applied in other hydrocarbon fields to reduce costs and time of drilling operation.
Applied Newly Developed Technology to Overcome Deepwater Completion Difficulties
Authors: Mohamed Omar Y. , Waters Ray , Eid Said , Aly Taher , Hassaballa Sherif Aly
Published: December 2007

A major issue for the deepwater high-rate gas completions in the Simian/Sienna field off the coast of Egypt was the placement of an effective sand-control completion in the presence of highly reactive shales. Analysis showed the most productive completion method to be an openhole completion. However, this presented a challenge, as the shale encountered during the drilling phase was very reactive and could destabilize during completion equipment placement or during pumping operations such as gravel packing.

One of the most concerning obstacles of open hole gravel packing is exposed reactive shales that can destabilize. If the shale section of the wellbore swells or flakes off, they can prevent running of the gravel-pack assembly to bottom, plug screens and/or collapse into the wellbore to prevent complete gravel placement. Isolating the shale section behind casing will solve the problem; however, this process most often means having to reduce the screen size to be used, which may impede production.

A completion design using two newly developed technologies and other carefully selected proven techniques was applied to minimize the risks of shale instability. A new design of an alternate path screen system was chosen because of its ease of assembly, ability to transport gravel-pack slurry past annular blockages such as collapsed shales and its minimization of slurry exit velocity from the alternate path tubes while packing. Another new technology that was selected for application was the use of a non-ionic visco-elastic surfactant to transport the gravel-pack sand downhole. This fluid was chosen for its shale stability properties, excellent sand suspension properties and the high-return permeability characteristics of the fluid. Application of these technologies and observing other best practices mitigated the risks associated with gravel packing in an open hole in the presence of reactive shales.
Simulation Investigations for Enhanced Performance of Beam Pumping System for Deep, High-Volume Wells
Authors: Ghareeb Mohamed M. , Shedid Shedid A. , Ibrahim Mazher
Published: December 2007

Worldwide there are almost 920,000 producing oil wells, about 87 % of these wells are operated using different artificial lift methods and roughly distributed as: 71 % are producing using beam pumping system, 14 % using electrical submersible pumping (ESP), 8 % using gas lift and 7 % using all other forms of lifting systems.

This study was undertaken using advanced predictive methods, high strength rods, optimum pumping mode, and unit geometry to optimize the performance of beam pumping system for deep high volumes oil wells. Three geometries of different surface pumping units were analyzed and studied including, conventional, Reverse Mark and Mark II units. Each geometry of these three types has been subjected to different design features that affect torque and different linkages affecting its kinematics behavior. The highest strength sucker rod string, beam unit geometry, stroke length, pumping speed and subsurface pump size were varied and analyzed jointly to obtain optimum pumping parameters capable to produce maximum fluid at different well depths. This study considered and applied many variables including; well depths from 1,000 to 15,000 ft, three different rod grades, water cuts from 0.0 to 100 %, different pump sizes from 1.25 to 5.75 in, stroke lengths from 100 to 260-inch, and non-API sucker rod grades.

The results indicated that the lifted liquid volumes and pump seating depths for deep wells can be effectively increased using the beam pumping systems. The surface unit geometry has shown a crucial effect of increasing the produced quantity from deep wells. The study recommended using conventional pump unit for shallow depths up to 8,000 ft. The enhanced geometry pumping units of Mark II and reverse Mark have been proven the superior type for deep high volumes wells because it required the least torque to lift the same quantity from different well depths. The study also presented successful field applications for deep wells producing high volumes.
Flow Pattern and Frictional-Pressure-Loss Estimation Using Neural Networks for UBD Operations
Authors: Ozbayoglu Evren M. , Ozbayoglu Murat A.
Published: December 2007

Underbalanced drilling is a very commonly used technique in many drilling applications. Usually, gasified fluids are preferred for achieving underbalanced conditions. Proper estimation of hydraulic requirements becomes a more important issue for trajectories with highly-inclined angles and longer sections. Flow of two-phase fluids through circular pipes has, relatively, been well understood. However, flow of two-phase fluids through annular sections is still a challenge. Many attempts have been conducted to model two-phase flow through annular geometries, but still there exists an uncertainty at this area. It has been observed that, for annular geometries, hydraulic diameter concept is not applicable for estimating flow patterns or frictional pressure losses using the models developed for circular pipes. This study approaches to estimate the flow pattern and frictional pressure losses of two-phase fluids flowing through horizontal annular geometries using Artificial Neural Networks (ANN) rather than proposing a mechanistic model. Experimental data collected from experiments conducted at Middle East Technical University, Petroleum & Natural Gas Engineering Multiphase Flow Loop, as well as from literature in order to train the ANN. Flow is characterized using superficial Reynolds numbers for both liquid and gas phase for simplicity. The results showed that ANN could estimate flow patterns with a high accuracy (error is less than ± 5%), and frictional pressure losses with an error less than ± 30%. It is also observed that proper selection of ANN is important for accurate estimations.
Automatic Coordinated Control of Pump Rates and Choke Valve for Compensating Pressure Fluctuations during Surge and Swab Operations
Authors: Nygaard Gerhard H. , Johannessen Erling , Einar Gravdal Jan , Iversen Fionn
Published: December 2007

In this paper we present new methods for coordinated control of pump rates and choke valve for compensating pressure fluctuations during surge and swab operations.

In hydrocarbon well drilling, automatic control of the choke valve improves the control of the bottom-hole pressure. This has made it possible to drill wells where it previously was not possible to reach total depth, due to narrow pressure margins in the reservoir. This concept is developed further in this paper, to also include automatic control of pump rates, coordinated with the choke valve control.

In configurations where the choke valve is fitted with a flow rate controllable annulus back-pressure pump, the situation calls for structured methods for automatic and coordinated control of the main mud pump, the back-pressure pump and the annulus return choke valve.

In this paper, well known methods for multivariable control are applied to the drilling process. These methods are based on identification of coupling and interaction between system input (controllable variables), e.g. pump rates and choke valve settings, and output (measured or estimated variables), e.g. pressure at given depths. It is shown how the well pressure profile can be kept within tight margins, subject to disturbances such as drillstring movement in surge and swab operations.

Automatic coordinated control is shown through numerical simulations on a detailed, space-discretized well model. Comparisons are made with the case of complete manual control and the intermediate case where only the annulus return choke line pump is automated, using a simple linear controller.

The results with automatic coordinated control of pump rates and choke valve are very promising - the performance of such a solution, measured by variance in pressure fluctuations, is improved - compared to both the case of manual control and the case of only automated choke line pump control.