bluuebunny/crossref_metadata_2025 huggingface dataset:
Identifying the Optimum Development Plan for the Western Area of Elgin/Franklin in the North Sea
Authors: Naylor P. , Cutler J. , Denham M. K. , Ribeiro P. C. D.
Published: December 2007

The Western Area Development (WAD) involves the Glenelg and West Franklin undeveloped discoveries which are located in the UKCS Central Graben, to the west of the Elgin/Franklin (E/F) asset. E/F is one of the largest high pressure, high temperature producing asset in the world and involves gas condensate reservoirs at 1,100bara and 190degC. The WAD is at similar conditions and two drilling strategies involving up to five new wells were proposed: Strategy-A: Drilling from the existing E/F platformsStrategy-B: Drilling from a new wellhead platform (WHP) which would be constructed over West Franklin

Strategy-A involved high step-outs of more than 4,000m, which have not previously been attempted under the extreme WAD conditions. The drilling risk associated with Strategy-A was greater than with Strategy-B but, to compensate, Strategy-A offered the prospect of lower capex and earlier production.

This development decision involved complex interactions between conflicting issues and the best way forward was not obvious. Decision Risk Management (DRM) provided a structured and auditable analysis of the optimum development strategy, taking risks and uncertainties into account. A decision risk model was constructed which involved fifteen uncertainties and calculated the drilling, completion and hook-up schedules, production profiles and corresponding cash-flow profiles. The model identified the set of decision options that generated the best net present value (NPV).

Drilling from the existing E/F platforms (Strategy-A) gave the highest expected NPV. The decision to pursue Strategy-A was robust and Strategy-B only became the favoured option when the high step-out drilling durations became more than double the expected value, or the WHP capex was reduced by about 45%.

This structured and open approach enabled the Partners to move forward and sanction Strategy-A.
Field-of-the-Future Program: Planning for Success
Authors: Reddick Chris
Published: December 2007

BP is in the process of implementing a programme called FIELD OF THE FUTURE covering the development and deployment of technology and business process solutions to most aspects of oil and gas field operations – from reservoir to export, in both mature and new fields, onshore as well as offshore.

This program is focussed on leveraging real-time or near realtime data to improve both short-term operational performance and long term recovery. There are a number of challenges associated with this program, not least being that it has to be demonstrably focussed on the highest value opportunities in BP's portfolio, and that the content of the program needs to be seen to be value adding by the business. Both of these challenges require deep engagement with the business around the question of value – how it is defined, accessed and measured.

Further, since BP's program is impacting a number of its Business Units simultaneously, it is important that all lessons learned from the implementation of this program are shared as rapidly as possible. In many cases these lessons are not simple extensions of current practice but rather a very significant shift in the way of working which will have a profound and lasting impact on BP's operations.

This paper describes the approach that BP has taken to assessing the value opportunity from its FIELD OF THE FUTURE program, how it has been refined to address specific challenges in BP's businesses, how these are being measured and how they are being used to shape the content of the program for maximum impact.

The paper also describes the approach taken by BP in sharing lessons learned from the implementation of the program.
Control of Multiple Zone Intelligent Well to Meet Production-Optimization Requirements
Authors: Konopczynski Michael , Ajayi Arashi
Published: December 2007

The application of intelligent well has greatly increased, however, integrating real-time data into a reservoir management work flow, and accurately predicting the hydrocarbon delivery to meet optimization requirement is still an elusive task. This paper presents a single intelligent well optimization strategy and attenuated IPR technology to fill this gap. By referencing individual zone production to one nodal reference point, a general flowl model was developed to combine the fluid flow from individual zones. The model integrates each individual zone's IPR with the production constraint equipment's flow performance to generate attenuated IPR's corresponding to the relative ICV choke setting. By integrating this attenuated-IPR with tubing flow performance, the hydrocarbon deliverability of the intelligent well and production fluid allocation of each zone can be reasonably predicted. Furthermore, to convert the real-time monitoring data into tangible value, this paper has proposed a two intelligent well optimization strategies. By combining the gauge data with a real-time flow distribution model, the production allocations of individual zones can be predicted. The attenuated IPRs provide operators reliable data to accurately predict the hydrocarbon delivery of the well and enable them to make decisions to meet optimization requirements.

Assuming a hypothetical two-zone intelligent well case, a computer model was developed to demonstrate this attenuated IPR method. This work provides engineers with a reliable tool for designing, analyzing and optimizing the production and downhole ICV operations of the multiple zone intelligent production well.
Field Operations Strategy Under Uncertainty in El Carito Field, North of Monagas, Venezuela
Authors: Khan K. , Arcia L. , Quijada Q. , Rodríguez J. , Monterola L. , Otaiza O. , Noriega R. , Vásquez Y. , Machin J. , González A. , Figuera L. , García A. , Chacón J. , López L. , Guarique J. , Quiroz F. , Chacon A. , Alvarado M. , Saputelli L.
Published: December 2007

El Carito field is a giant, deep onshore reservoir in East Venezuela; and it is the second largest field in the north of Monagas basin. Field exploitation started in 1986, and it has been subject to a huge gas injection project to maintain 100% fluid replacement as the optimal exploitation strategy.

Market thrust, gas utilization guidelines, and production increase expectations were the drivers calling for implementaation of an in-depth analysis of the reservoir's history and forecast performance. The proposed analysis would require the application of novel methodologies for modeling uncertainty and for analyzing optimium scenarios.

A multi-disciplinary team for El Carito field business unit implemented an integrated asset modeling (MIAS) methodology for selecting the optimal field exploitation strategy. The objective was to assure optimal short-term field operating strategies in agreement with long-term reservoir management objectives with social and environmental responsibility.

This paper describes the methodology used for developing a field operating strategy and a long term field exploitation plan based on the analysis of historic production profiles, drilling and workover success statistics, production enhancement practices, and world–class best practices available for modeling uncertainty and for optimizating scenario.

The applied methodology established fast and consistent, integrated support for decisions and identified quick, constructive actions for immediate implementation in the field. These actions were consistent with optimal long-term reservoir management strategy that best utilizes the subsurface resources and the surface facilities.
Effect of Surfactant on Volume and Pressure of Generated CO2 Gas
Authors: Bakhtiyarov S. I. , Shakhverdiyev A. K. , Panakhov G. M. , Abbasov E. M.
Published: December 2007

The experimental studies were conducted to estimate the effect of surfactant additives on the volume and the pressure of the CO2 gas generated according to the new proposed technology. An experimental device was designed and built specifically for these purposes. The designed setup allowed initiating and controlling the reaction between the "gas-yielding" (GY) and "gas-forming" (GF) agents proposed by this technology. The temperature was controlled, and the generated gas pressure and volume were recorded during the reaction process. Three types of surfactants were tested to estimate the effect on volume and pressure of generated CO2 gas. The preliminary experimental results on CO2 gas pressure measurements demonstrated that the gas pressure increases with (i) surfactant addition, (ii) decreasing the temperature, and (iii) increasing salinity of the system.
Using PDA Technology for Health, Environmental, and Safety Process Improvement
Authors: Dudics D. D. , O'Toole W. P. , Schmillen M.
Published: December 2007

Introduction

In 2003, Occidental of Elk Hills, Inc. (OEHI) developed several tools to help manage safety proactively. These tools included the "Contractor Scorecard" and the PDA-based "Self-assessment" Program. In 2005, Thums Long Beach Company (THUMS) a subsidiary of Occidental of Long Beach, Inc., reviewed these innovative technologies and collaborated with OEHI to transfer them to the THUMS Unit. The PDA-based program in particular has been instrumental in improving safety compliance and overall performance.

Background

The "Self-assessment Program" (the Program) developed is dependent on PDA technology to provide a simple means and method to capture data, analyze the information and confirm HES compliance. The Program developed is highly automated allowing for quick, easy data gathering while still providing report capability that is simple, direct and informative. The crux of the Program is the PDA which provides the convenience, flexibility and speed unlike most paper-based systems.

The PDA originally selected was the Palm Zire-71 because it was user friendly, MS-Access compatible, easily programmable and durable. This PDA included camera capability which was helpful for facility audits, incident investigations and similar activities where photos could be stored in e-file format; transmitted and/or incorporated into reports. Data gathered in the field could be easily downloaded daily into an MS-Access dB using the standard PDA cradle and "thinkDB" software. Once the data was downloaded trending, analysis and reporting was easily performed.

Safety or compliance "checklists" provided the foundation for the "field data" gathered and analyzed. These were initially written in "Pendragon – Forms 4.0" because it was flexible software and provided easy programming capability. The compliance or "self-assessment" checklists developed and programmed into the PDA's covered some 70 subject. These were derived from OSHA regulations, company policies, procedures and similar requirements. Checklists subjects included, by example, hot work, lock-out/tag-out, confined space and spill prevention. These checklists or inspection sheets provided a uniform means and method for any interviewer to ask a series of questions or observe a number of activities and record objective answers systematically.

The PDA checklist also provided a list of causal factors that the interviewer could input for those answers to questions that were non-compliant. This was intended for later analysis of the data to determine underlying causes of non-compliance where improvement efforts could be focused. (See Figure 1.0, Lock Out / Tag Out Checklist)

Realizing the benefits of such technology and the proactive means of managing contractor safety compliance, the THUMS' organization decided to adopt the process for their Unit.
Road Map to Establishing Effective Shared Environmental Governance
Authors: Haider S. A. , Al-Khamees K. M. , Zaher A. , Al-Yakoob S.
Published: December 2007

The state of Kuwait is moving forward to engage international oil companies (IOCs) in the development of some of its oil fields for a limited period under a contract with the recently established Oil Development Company (ODC). The aim of IOC involvement is to improve performance in a number of areas in the upstream sector including those related to environmental activities.

Implementation strategies for environmental regulations, being the responsibility of the Kuwait Environmental Public Authority (KEPA), are still evolving. Nevertheless, compliance with Kuwait Environmental regulations must be timely fulfilled. This situation could be of a concern especially if delegation of authority by KEPA to ODC for implementing the environmental regulations is not acceptable.

This paper describes an innovative approach involving cooperation between KEPA and ODC through a partnership framework. The framework is designed to enhance KEPA capabilities and ensure proper enforcement of Kuwait environmental laws and regulations in a manner that parallels the effectiveness of compliance strategies included in the IOC's Environmental Management Systems (EMS).

The cooperation framework is activated through an implementation mechanism that involves a pre-operation compliance assessment and regulatory governance. During the pre-operation compliance assessment, the compliance status of facilities to be operated by IOCs will be determined, while regulatory governance during IOC operation will consist of an implementation framework for Kuwait environmental laws and regulations through cooperation between KEPA and ODC. Environmental compliance audits are part of the implementation mechanism that the ODC would adopt in dealing with the IOC's, which are important management tools to ensure that the facilities operated by IOCs that discharge, emit, prepare, manage, store, or dispose of pollutants or contaminants are in compliance with Kuwait environmental laws and regulations.
Integrated Project and Data Tracking Saves Expertise and Time
Authors: Xue Yan , Yang Anping
Published: December 2007

Many companies are faced with project and data tracking issues. How to make information related to a project readily available to the people doing the project? When people move to different projects or even to different companies, how to keep the expertise in past work on the projects and make such experiences available to new people coming to the projects?

This paper describes how a web-based database management system is used to address such issues. Each day, users input project notes, questions, and files to be shared into the web-based system. Users in different office locations and different time zones can share the information easily, either in office, at home, or during travel. Managers can review project progress anytime anywhere, such as during an offsite meeting. Questions about the project can be answered by people in different offices or different time zone. Besides project notes and files, data available to the users may include completion information, workover activities, markers, well logs, petrophysical analysis, seismic locations and views, production data, and accounting data. To keep the system simple to use, different level of complexity can be selected, and different levels of security can be assigned to different users.

Management leadership is needed to take full advantage of such system, since not everyone is used to writing notes when they work. Once implemented, such system can save lots of time in tracking a project and getting new people familiar with the project.

A web-based integrated tracking system can significantly reduce the time needed for a project team to retrieve information. Information is also saved even when people move, making it easy for new people coming to the project to continue the work, or for people in other projects to reference the experiences.
A Rigorous Analytical Model for Fluid Flow in Drainholes of Finite Conductivity Applied to Horizontal and Multilateral Wells
Authors: Guo Boyun , Zhou Jinkui , Liu Ying , Ghalambor Ali
Published: December 2007

Use of horizontal and multilateral wells for oil and gas recovery has become a common practice in the petroleum industry. It is generally recognized that most horizontal wells do not produce oil and gas at the expected production rate. The discrepancy is mainly due to the fact that it is unclear as what constitutes the "expected production rate." The expected production rate is usually the production rate predicted by the mathematical models that were derived on the basis of the assumption of infinite-conductivity drain hole. Although a number of mathematical models are available for predicting the productivity of horizontal wells, they are not easy to use due to their common nature of mathematical complication and numerical treatments. This paper presents a simple and rigorous mathematical model for estimating the productivity of horizontal wells.

By rigorously coupling reservoir inflow and drain hole hydraulics we derived an equation for pressure distribution in the horizontal drain hole in this study. A simple function for fluid flow rate distribution in the drain hole was then developed. An equation for deliverability of the horizontal drain hole was obtained by evaluating the flow rate function at heel. This new model was compared with three existing mathematical models and field data. The comparison shows that the new model has two advantages over other models: 1) it is more accurate than other models, and 2) it is very easy to use. This paper provides petroleum engineers a simple tool for accurately predicting productivity of horizontal drain holes.
Case Study Development of Low-Permeability and Low-Pressure Reservoir Block Bao14 by Fracturing and Water Injection
Authors: Liu Wei
Published: December 2007

Block Bao14 has a burial depth of −850~-1420m, porosity of 17.0%, permeability of 27.0×10−3μm2 and orginial formation pressure of 12.3MPa. However, the pressure in the reservoir declines very quickly, so it is a typical low permeability and low pressure sandstone reservoir. The paper will present the developmemt situation of the reservoir with both fracturing and water injection. Due to the existence of the induced fractures, this kind of development mode poses great risks, i.e. premature water-flooding or water channeling may happen to the oil wells if the azimuths and lengths of the fractures are not compatible with the injection- production patterns and parameters. The following methods are adopted to solve the problem. The azimuths and lengths of the fractures are measured by the electric resistivity tomography and microearthquake method to be the bases for adjusting the injection-production patterns and designing the injection-production parameters. The relationships between the injection-production parameters, fracture parameters of the oil or water wells at different locations in the well pattern and the sweep efficiency, production and watercut under the conditions of induced fractures are simulated and calculated and the fracture lengths and flow conductivity of the oil and water wells are optimized. With the application of low temperature gel break activator, the activity of APS is activated at low temperatures and the process of peroxy release by APS is controlled to control the chemical reaction rate so that the gel breaking time of the fracturing fluid can be controlled to ensure quick gel breaking of the fracturing fluids at low temperatures. An integral pipestring for fracturing and flowback is used. With multistage gas lift valves installed at different locations on the fracturing pipestring, continuous flowback of the fracturing fluid can be realized, improving the flowback rate and efficiency. Resin coated sands are tailed in to effectively contol the the flowback of proppants after fracturing without any effects on fracturing stimulation results. Based on fracture azimuth and length, alternate water injection is applied horizontally and cyclic water injection is applied vertically and intermittent water injection is applied in some heavily flooded areas, greatly improving water injection sweep efficiency and effectively controlling the premature occurrence of water-flooding and water channeling. 20 wells have been put (converted) into water injection in Block BAO14 under this mode with water injection of 184m3/d and cumulated water injection of 36.7761×104m3. Altogether 78 oil wells have been put into production with fluid production of 605t/d, oil production of 289t/d, overall watercut of 52.17%, oil recovery rate of 2.61%, oil recovery rate for the residual recoverable reserves of 38.4%, cumulated oil production of 29.1728×104t and degree of reserve recovery of 7.76%, achieving favourable overall development results of the block.
Solution for a Long-Standing Cementing Challenge—Engineered Cement Set Control Additive
Authors: Sorgard Eirik , Viali Rodrigo
Published: December 2007

Solution for a Long-Standing Cementing Challenge— Intelligent Cement Set Control Additive Industry has always found it challenging to cement long zones with a single slurry system. A huge temperature differential exists between the bottom and the top of a long cement column. Cement slurry designed for the circulating temperature at the bottom of the long column will sometimes fail to set at the low temperatures at the top of the cement column. These results in rig nonproductive time and in certain cases can lead to well integrity problems.

While setting unplanned kickoff plugs or plugging and abandoning wells, the bottom hole temperature may not be very well known. The slurry setting is sensitive to temperature, and the setting time can change substantially if the actual bottom hole temperature is different from that used for design. This leads to failure of the cement plugs. This issue is more pronounced around 200°F.

A new generation of engineered cement set control (ECSC) additive has been developed to successfully cement wells in the scenarios mentioned above. The additive works intelligently and not only provides sufficient placement time for bottom of long cement columns where temperature is higher, but at the same time allows for fast compressive strength development even at the top, where temperatures are lower.

A single slurry design incorporating the additive has been used successfully in setting multiple plugs at different depths, with varying bottom hole circulating temperatures, demonstrating the relative insensitivity of the retarder to temperature variation.

This paper discusses successful use of the additive in the field for setting multiple plugs at varying depths and temperatures using the same slurry design. Field cases with results related to the various applications will be provided.
A Simple Productivity Equation for a Horizontal Well in Pseudosteady State in a Closed Anisotropic Box-Shaped Reservoir
Authors: Lu Jing , Tiab Djebbar
Published: December 2007

This paper presents a simple productivity equation for a horizontal well in pseudo-steady state in a closed anisotropic box-shaped reservoir, using a uniform line sink model. A new equation for calculating pseudo skin factor due to partial penetration is also proposed. Compared with the equations for horizontal wells in pseudo-steady state in the literature, the new equations are more practical and easy to use in the field practice. They are derived by solving analytically the involved three-dimensional partial differential equations and are extracted from a very complex general solution,

The effects of the following parameters on productivity have been investigated: well location, pay zone thickness, well producing length, principal permeability, and dimensions of drainage volume. It is concluded that, though each of these parameters has an effect on productivity, the well length and the permeability perpendicular to the well in the horizontal plane have the strongest influence.
First Installation of an Openhole Expandable Sand-Screen Completion in the Iranian Oil Fields Leads to Operational Success and Production Enhancement—A Case History
Authors: Hooshmandkoochi A. , Ghorbani F.
Published: December 2007

Expandable sand screens were developed to overcome the shortcomings of both existing sand control techniques, while also providing some unique benefits. The first commercial application of this technology took place in January 1999. Since then, their use has spread quickly to all parts of the world and in many diverse applications. As of June 2005, over 340 installation of expandable sand screen (ESS) had been run in over 700 years of combined production.

The productivity performance of the ESS has been shown to be very good, with an average skin of 0.3 being achieved in recent openhole applications. ESS completions generally perform better than the baseline models. Where field comparisons were possible, they also performed better than alternative sand control completions.

However, its introduction and acceptance into the Iran has been slower in coming. It was not until in 2005 that National Iranian Oil Company (NIOC) decided to complete its Mansuri oilfield, well MI–34 sidetrack, using openhole expandable sand screen for sand control, thus making it the first such completion in the Iranian oilfields. This paper will provide a brief overview of expandable sand screen, its construction and advantages and will describe some of the issues addressed in this well completion. It will provide details of the installation procedure, the fluids employed and well production results achieved. It will conclude that the use of expandable sand screen as an alternative to conventional sand control methods in the Iranian Oilfields is viable.
Microbial Enhanced-Oil-Recovery Technologies: A Review of the Past, Present, and Future
Authors: Maudgalya Saikrishna , Knapp Roy M. , McInerney Michael J.
Published: December 2007

One form of tertiary oil recovery that does not require exceptional investments is microbial enhanced oil recovery (MEOR). With abundant and easily producible oil supplies dwindling, MEOR could be an uncomplicated aliment to conventional water flooding. Unfortunately it has not gained credibility in the oil industry due to technical and economic reasons. To better understand this problem, a survey of reported MEOR field trials from across the world was conducted here. The survey shows some widely prevalent practices in most of the trials. Few tests could explain the mechanics of oil recovery or presented any post treatment analysis and explanation of to how results were calculated. And some showed improvements that appeared disproportionate to the treatment size. Based on trends observed in the survey results, recommendations are made to overcome barriers to widespread use of MEOR and gain credibility with more users. One recommendation is to standardize test procedures and reporting of results and analysis. This would be the best way to avoid contradictory interpretations of MEOR results. The initial few trials will be expensive if all the pre-treatment and post-treatment recommendations are followed. But the benefits of conducting a few systematic and well designed tests to fully evaluate the potential of MEOR and bring credibility outweigh the expense.
Prediction of Slurry Permeability, k, Using Static Gel Strength (SGS), Fluid Loss Value, and Particle Size Distribution
Authors: Bahramian Y. , Movahedinia A. , Rasaei M. R.
Published: December 2007

Gas migration through the cement column is considered as one of the most sever encountered phenomena during drilling or completion procedures, and has been recognized as one of the most troublesome damaging effects of the petroleum industry on the environment. There are many theories explaining the migration of gas through the cement which mainly considered the following as major factors contributing to gas migration: fluid density, mud removal strategy, cement slurry design, cement hydration processes, cement-formation-casing bonding and cement mechanical properties. Considering cement slurry design, the permeability of the slurry during transition state is explained as one of the main controlling parameters. Therefore low permeability is defined as one criterion for good cement formulation.

In this paper, an approach has been presented which relates permeability, k, to SGS, fluid loss value and pore size distribution of the cement. Modeling k goes through the consideration of the cement as a two-phase porous-elastic material with a changing structure represented by variation of SGS and fluid loss value with time.

The pore sizes of the particles are introduced in the model by using Carman-Kozeny equation, in which the permeability at the beginning of transition state (t = 0) is calculated. The Sabins et al. equation, 1982, which is originally developed to compute pressure drop due to gelation, is used as the basic equation to relate SGS and fluid loss value to k (along with Darcy flow equation). Maximum Darcy flow rate, qmax , which is, according to Sabins et al, simply measurable by using static gel strength and slurry permeability tester, is used to reflect the effect of fluid loss values on k values. Finally the predicted k-values by the equation is compared with measured data.

The approach can be used to optimize cement formulation and simulate gas migration through the cement column.
Finite Element Studies of Near-Wellbore Region During Cementing Operations: Part I
Authors: Gray K. E. , Podnos E. , Becker E.
Published: December 2007

A wellbore cement sheath is expected to provide zonal isolation and borehole integrity during well construction and well life. Cement sheaths mechanically interact with other elements in the wellbore region to stresses from geological processes and operational activities. Quantifying these interacting physical components and processes has technical, economic, and environmental implications of great, and growing, significance.

Staged finite element procedures during well construction sequentially consider the stress states and displacements at and near the wellbore. The model replicates complicated stress states arising from simultaneous action of far-field stresses, overburden pressure, cement hardening and shrinkage, debonding at the interfaces, and plastic flow of cement sheath and rock formation. Presently, temperature and flow are not included. The technique tracks the time-dependent behavior of cement slurry, curing (with or without shrinkage), and hardened cement during the critical period after slurry placement.

Material models for casing, cement and rock formation, failure criteria for cement, formation and interface bonds were calibrated using published information and experimental data. Calculations were conducted for various loading and unloading scenarios, geometric configurations, properties of rock formations, and cement slurry formulations. Results are discussed in terms of field implications, for example: (1) interface micro-channels may or may not develop, depending upon shrinkage magnitudes; (2) simplifying modeling assumptions that are often used, such as 2-D stresses and/or deformations, may obscure critical casing, cement, and formation behavior in the wellbore region, and in the producing horizon.

This paper, part of a series quantifying the interacting physical components and processes at and near the wellbore region, initiates useful comparisons of analytical results and field realities. The series illustrates and compares results and practical implications for simple to increasingly complex, but more realistic assumptions, such as isotropic/directional stress states, and isotropic/anisotropic casing, cement, and formation material parameters.
An Approach To Apply the Gas in the Annulus To Assist Pumping Oil in High-GOR Wells
Authors: Yonghui Liu , Yingchuan Li , Xiaoqi Li , Guilin Tang
Published: December 2007

Gas lift is a good artificial lift for those high gas/oil ratio (GOR) wells. But the positive displacement pump is used on many special conditions such as the limitation of high pressure gas, large equipment investment and low remaining recoverable reserve. To decrease the gas into the pump, the gas would generally be separated at bottom hole, then enter the annulus between the tubing and the casing (tubing-casing annulus), eventually flow in air or enter oil pipeline by many control valves at wellhead. In this system, the gas is a potential damage factor to the pump. So the pump efficiency is low and the frequency of pump checkout is high.

In this paper, a new approach is presented. One or two gas lift valves are installed on the tubing near the wellhead. The other equipments are same as the conventional system. While the casing pressure reaches the aimed value, high pressure gas in the annulus automatically enter the tubing. This lightens the weight of the fluid in the tubing above the working valve, which assists pumping the liquid.

This approach is applied in sucker rod pump system in Wendong oilfield. Dynamometer cards from 2 typical wells indicate that the pump efficiency is improved and the daily fluid production rate is enhanced. Then a similar approach is applied in Electric Submersible Pump system (ESP) and the same good result is obtained. This paper presents the description of this new approach and reports the results obtained in those field trials. The energy-saving theory is analyzed and the design procedure is given.
Liquid Unloading of Depleted Gas Wells in the North Sea and Continental Europe, Using Coiled Tubing, Jointed Pipe Velocity/Insert Strings, and Microstrings
Authors: De Jonge R. M. , Tousis U.
Published: December 2007

Flow from gas wells is often hindered due to water loading problems as fields mature, which often require remedial completions for maintenance of well flow. Velocity and insert string completions, using coiled tubing, jointed tubular and continuous foam injection via micro strings are techniques used to prolong production from these depleted gas wells.

A wide variety of velocity and insert string operations have been performed. To date the authors' in-house experience includes a total of 32 insert/velocity strings deployments in wells offshore in the UK, and 40 in the Netherlands and the rest of Continental Europe, both offshore and on land. Nearly 20 micro strings (0.25″) have been deployed in Continental Europe during the last 3 years. The sizes of the deployed coiled tubing velocity strings range from 1.5″ OD to 3.5″ OD, and 13Cr ‘Flush Joint Liner' strings for gas wells with high CO2 content, range from 2.875″ to 3.5″.

In this paper the aforementioned technologies are summarized, based on an extensive list of case histories of jobs performed in the North Sea and Continental Europe. It describes the equipment, engineering and technologies used for installation of these strings by hanging off either below the SSSV or at surface, as well as the offshore operational challenges experienced, due to small footprint installations, the installations being NUI's (Normally Unattended Installations) and low crane lifting capacities.

The number of engineered and deployed insert/velocity strings represent a vast array of lessons learned, optimizations, and successful operations. The comparison between the different techniques offers a base for preparation and optimization of liquid unloading techniques. A decision tree has been prepared to assist in choosing the suitable installation type.
Development of Unconventional Gas Resources: Stimulation Perspective
Authors: Zahid S. , Bhatti A. A. , Khan H. A. , Ahmad T.
Published: December 2007

Natural gas is an important global energy resource. In the last few years its consumption has increased significantly and being a cleaner fuel it is certain that in future it will play an ever increasing role in satisfying the increasing energy demand across the world. In order to meet the growing energy demand, exploration and production has increased across the world. However, due to the higher depletion rates of oil & gas reserves as compared to their discoveries, today the international energy sector is seriously thinking of developing unconventional energy resources, especially gas, so that the future energy needs can be met not only from an economic but also from reduced environmental impact point of view.

Three such Unconventional gas resources are tight gas reservoirs, coalbed methane and shale gas. These resources hold great potential as a source of natural gas (e.g. USA has the potential of recoverable gas of about 350, 100 & 45 Tcf from tight gas resources, CBM and shale gas respectively) and at the moment extensive work is being done for the development of these resources across the world. But, to produce these resources (gases) economically and efficiently well stimulation plays a major role in achieving the optimal target production from these reservoirs. Unconventional gas reservoirs require the formation to be fractured by hydraulic means to improve the formation productivity by providing a conductive path and joining the existing fractures and cleats in the reservoir.

The purpose of this paper is to discuss the role and effectiveness of different stimulation techniques in the development of unconventional gas resources. The improved stimulation has made a positive impact on the development of these resources which were considered uneconomical to produce due to lack of properly developed stimulation methods. Due to improved stimulation treatments, recovery from these resources has been enhanced greatly and producing gas from these unconventional gas reservoirs is far more economical and feasible than it was in the past. This paper presents a complete overview of the current scenario of unconventional gas resources and focuses on the fracturing stimulation techniques for the development of Unconventional gas resources.
The Important Second Fracture and Its Optimal Placement for Maximizing Production
Authors: Surjaatmadja Jim B.
Published: December 2007

Placement of a fracture in a formation has become a well-understood process in the industry. Recently, this practice was improved by the introduction of a method to properly initiate the fracture into a specific direction using super-high-energy jetting. A drawback of this jetting method though is not knowing exactly where the far-field fracture has gone. Although we know that the fracture will extend in the local minimum-stress direction, it is not known where that direction might be. In all probability, the fracture has gone into a less-than-desired area in the formation, and will result in only an "acceptable" improvement of production.

It was once thought that refracturing merely reopened existing fractures. Recently, however, it has been shown that refracturing can actually create new fractures. In addition, when refracturing causes older fractures to reopen, the results generally show that some new area has been reached by the fracture. It is the opinion of this paper that these new areas are not substantially different from the one reached by the first fracture because local depletion enhances the effects of the original stress regime.

This paper discusses a process whereby fractures are generated in a formation using at least two different fracturing techniques to reach formations in a manner not reached by conventional fracturing alone. In this process, the first fracture may achieve "acceptable" production goals, although the cost may be high. A second fracture is then quickly created to take advantage of the stress modification resulting from the first fracture. This rapid followup fracture is thus able to reach more productive rock not accessible to the initial fracture. Field data supporting the feasibility of this concept will be presented. Various situations where this approach could reap substantial benefits are also described.
Downhole Leak Determination Using Fiber-Optic Distributed-Temperature Surveys at Prudhoe Bay, Alaska
Authors: Julian J. Y. , King G. E. , Cismoski D. A. , Younger R. O. , Brown D. L. , Brown G. A. , Richards K. M. , Meyer C. A. , Sierra J. R. , Leckband W. T. , Sack J. K. , Julian F. C.
Published: December 2007

Distributed Temperature Sensing (DTS) is an emerging technology which allows temperature measurement and transmittal along the entire length of the well. An enclosed fiber-optic cable is deployed into the well to allow a continuous, real-time snapshot of the well's temperature profile. Since its introduction in 1995, DTS has had an increasing number of applications including determining production and injection profiles, monitoring stimulation operations, and performing gaslift surveys. This paper discusses DTS as a method for downhole leak detection based on a North Slope field trial conducted between 2004-2006. Twelve operations were performed using two different vendors’ retrievable DTS systems, successfully identifying tubing, production casing, sand plug, and packer leaks. Theory, case histories, and future improvements are summarized in this paper. Additionally, a comparison between conventional leak detection logs is presented along with the advantages and disadvantages of DTS surveys.
Two-Phase Fluid Flow Through Fully Eccentric Horizontal Annuli: A Mechanistic Approach
Authors: Metin C. Omurlu , Ozbayoglu M. E.
Published: December 2007

The number of wells drilled using underbalanced technique is increasing rapidly due to the advantages of this technology, i.e., increased penetration rate, minimized lost circulation and differential sticking, reduced formation damage and many environmental benefits. During Coiled Tubing (CT) underbalanced operations, gas-liquid mixtures are commonly used. In order to accomplish a successful drilling program, hydraulic calculations concerning two-phase fluid system should be carried out carefully. Since the flow geometry is mostly fully eccentric annuli in horizontal section of the wellbore, a realistic mechanistic model is essential. Although there are numerous studies available for two-phase flow through circular pipes, less is known about the flow of two-phase fluids though annular geometries. Commonly used methodology is using hydraulic diameter for representing the annular geometry, and using the circular pipe correlations by replacing the circular diameter with hydraulic diameter. It is observed that a better methodology is needed for basic hydraulic calculations. Therefore, in this study, horizontal flow of gas-liquid mixtures through fully-eccentric annuli is investigated. A mechanistic model is proposed for estimating frictional pressure losses, which can be used for both circular pipes and annular geometries by introducing a representative diameter term. Flow pattern identification is developed inheriting basic concepts proposed by Taitel-Dukler1. The model results are compared with experimental data obtained from two different annular geometries (4.5in × 2.25in and 3.672in × 1.92in) at Middle East Technical University – Petroleum & Natural Gas Engineering Department – Cuttings Transport and Multiphase Flow Loop. It is observed that, for representing the annular geometries, introduced representative diameter works significantly more accurately than hydraulic diameter. Additionally, flow patterns can be estimated better if representative diameter term is used. It is concluded that, the proposed mechanistic model can identify the flow patterns correctly and estimate frictional pressure losses with an accuracy of less than 20% when compared with the experimental data.
Delivering Value for Tracking Coiled-Tubing Failure Statistics
Authors: Burgos Rex , Mattos Rafael Fernando , Bulloch Scott
Published: December 2007

The concept of tracking coiled tubing (CT) failure statistics for use in developing performance indicators is not new. It has been covered extensively as the subject of previous abstracts. Tracking relies on an established process for reporting and investigation of pipe-related failures allowing the collection of data from CT operations of a leading service provider, which has global representation.

The primary aim of the process is the identification of the immediate cause of the failure and, more importantly, the failure mechanism for the incident. Only with a good understanding of prevailing trends, if any, can remedial action addressing the root cause(s) of the problem be enacted. This is particularly important for an organization with more than 200 CT units and more than 750 CT strings in service over a wide geographic landscape. In an environment of high CT activity, which has been the experience of the last two years, the value of this process cannot be overstated.

The value to overall CT operations is demonstrated in two examples in which the identified failure trends became the focus of separate service delivery improvement initiatives. The first issue resulted in a change in the organization's policy for reel storage and maintenance, while the second caused a modification in the CT unit controls to properly address the root cause. An in-depth discussion of the issues and their mitigation is the subject of this paper.

The most recent paper on this subject presented information covering the period 1995 to 2000. This paper provides updated information on these CT performance indicators, presenting material from activities during the five-year period 2001 to 2005. The evolution of pipe failure trends is covered and contrasted against the changes that have taken place in the CT industry as a whole over the last decade.
Water-Shutoff Treatment in Wells With Single-String Multizone Completion Intervals (Brownfields)
Authors: Uadiale Victor E. , Otaru G. Oghie , Nwabueze Vincent O.
Published: December 2007

Due to the stacked nature of reservoirs in the Niger Delta, the predominant completion types are dual-string multizone and single-string multi-zone completions. These designs have been adopted to reduce the number of infill wells required for field development. However, they come with a disadvantage in regard to carrying out a successful intervention when water break through occurs.

Water breakthrough and high basic sediments and water (BS&W) are problems associated with fields having strong aquifer drive mechanisms. As a result, most exploration and production companies have learned to manage water production up to a tolerable limit, which is dependent on the water handling capacity of the installed facilities and also the economic cutoff limits for the wells in question.

The reason for this type of water management is the lack of confidence in the water shutoff remedial operations. From a survey carried out in the early 90s, it was estimated that only 35% success was achieved worldwide in water shutoff remediation. This low success rate is due to poor diagnosis, wrong selection of water shutoff solutions, and how complicated the well completion is with respect to the zone of interest to be treated.

Field X, 12, which consists of a large gas cap and a 100-ft total vertical depth (TVD) oil column, was developed with the single-string multizone completion design. Due to the presence of a strong aquifer in this field, water production started early and some of the wells were shut-in due to lift problems associated with the water production. A sidetrack option was considered as a means of bringing these wells back on production, but was not used because of the absence of a gas gathering facility for the field. As a result of production decline and lack of infill opportunities, cement-water shutoff and re-perforation intervention in the wells was adopted.

The objective of the cement-water shutoff was to ensure that the perforations, which were flushed, were completely sealed off and isolated and subsequently re-perforated shallower.

After slurry placement and squeezing, it is important to ensure that a good cement job has been performed. Operationally, the top of cement (TOC) is tagged using slick-line in a vertical or deviated well. If the TOC is not at the theoretical depth, then a top-up job is carried out with additional slurry. On the other hand, if the TOC is at the theoretical depth, then a pressure test is performed to confirm that the perforations are squeezed off.

For intervals behind the sleeve as in the case of Field X, ascertaining the TOC is technically impossible because the perforations are behind the production tubing. For such single-string selective completions, only a pressure test can be performed to confirm that the perforations are squeezed off. This paper addresses the planning, operational and the learning from the through-tubing water shutoff campaign successfully carried out on wells with single-string multizone completions.