bluuebunny/crossref_metadata_2025 huggingface dataset:
Application of Critical Technologies Enabling Low Cost Development of Thin-Bedded Heterogeneous Gas Reservoirs in the North Malay Basin
Authors: Alessio L. , Howells C. , Chu J. , Abbas S. A. , Wade B. , Ball S.
Published: December 2007

CS Mutiara Petroleum is a Petronas Carigali – Shell Malaysia joint operating company formed in 2001, operating since then the PM301 and PM302 exploration PSCs. The company enjoyed a 100% exploration success rate in the North Malay basin, and is now rapidly transitioning into a development venture.

A total of six discoveries were made since 2002 within the PM301 block. The nature of these discoveries: modest size, stacked pay, fluvio-marine transitional geological setting, high heterogeneity, partially sub-seismic resolution, creates a range of technical and economical challenges. The application of a number of specific technologies, notably to reservoir characterization are seen key to unlock the potential of these discovered volumes.

Technically, in the early stages, the seismic attribute-based prediction of gas sand, using a simultaneous inversion technique, was the key enabler for exploration success, allowing to map the presence of coal versus water and gas sands. Now, success through the development phase requires the application of the following technologies:

Neural-net based seismic facies, aimed at resolving lateral heterogeneity at field scale and improving the understanding of the ranges of drainage areas for development wells Low resistivity pay analysis, geared towards understanding of both static (saturation, net-to-gross) and dynamic (permeability) parameters Multiple realisation 3D modelling, using stochastic simulation, guided by techniques borrowed from Experimental Design.

In addition to technical challenges, critical to unlocking these volumes is the economical optimisation of the cluster development, within a consistent portfolio management framework. This is done by using modelling at various levels: 3D modelling at field level, testing different geological concepts and the associated key uncertainties; those are then scaled up into an integrated surface-subsurface nodal network model to optimise the development of the discoveries as well as the near field potential remaining prospects.
Enhancing Field Management in Siberia by Quantifying Production Uncertainties
Authors: Tipping D. E. , Deschenya M. N. , Deimbacher F. , Kovyazin D.
Published: December 2007

An analysis of production data from a Lower Cretaceous western Siberia oilfield operated by TNK-BP suggested that the final recovery factor would not exceed 15% with one of the waterflood development plans under consideration. Such a plan clearly left scope for improvement. However, since there were limited surveillance data to infer current depletion from the 8 oil bearing beds, considerable uncertainty existed in locating the remaining reserves. This prompted an examination of the reservoir and well characteristics to quantity these uncertainties in the reservoir potential and, hence, ensure the future strategies to increase recovery are viable. To determine the uncertainty in predictions, it was necessary to create multiple predictive models all matched to observed field data. This matching process is extremely time consuming when undertaken manually. Our experience shows that one model requires about 9 man-months. As a result, we tested a procedure to accelerate the matching using a program with an automated history matching algorithm linked to the dynamic simulator. Although implementation of this method is still ongoing, it has demonstrated the following: Uncertainties are an inherent part of reservoir predictions. For field management, it is important to quantify them so they can be managed.Major increases in work productivity are achievable. Within a period of a week, after determining the uncertainties to be addressed, we obtained 7 different history-matched models each yielding a unique production profile prediction.

Based on the quantification of the uncertainties, we are changing our field management practices. For example, additional surveillance is planned to monitor the depletion in each bed. A further benefit is that this uncertainty evaluation methodology gives us confidence in identifying areas that need additional injection support.
Drilling with Casing Reduces Cost and Risk
Authors: Tessari R. M. , Warren T. M. , Jo J. Y.
Published: December 2007

More than 1.2 million ft of hole has been drilled in over 260 wells with retrievable casing-while-drilling tools. These wells have been drilled with seven casing sizes ranging from 4-1/2" to 13-3/8". The drilling system is composed of downhole and surface components that provide the ability to use normal oil field casing as the drillstring so that the well is simultaneously drilled and cased. The casing is rotated from the surface for most operations

The experience gained while drilling these wells has led to a better understanding of the advantages of the process. It's most effective applications have been to reduce the cost and risks associated with wells which routinely experience lost circulation when drilled conventionally; wells in which well control is difficult for tripping drillpipe; wells where excessive fluid loss into low pressure reservoirs impairs the production and ultimate recovery; and wells where it is difficult to get the casing shoe as deep as needed.
Global Field Results of a Polymeric Gel System in Conformance Applications
Authors: Eoff Larry , Dalrymple Dwyann , Everett Don
Published: December 2007

Water production becomes a major problem as hydrocarbon-producing fields mature. Higher levels of water production result in increased levels of corrosion and scale, increased load on fluid-handling facilities, increased environmental concerns, and eventually, well shut-in (with associated workover costs). Consequently, producing zones are often abandoned in an attempt to avoid water contact, even when the intervals still retain large volumes of recoverable hydrocarbons. Many polymer systems have been applied over the years to control undesired water production from hydrocarbon wells, with varying degrees of success.

For approximately eight years, a polymer gel system based on an acrylamide/t-butyl acrylate copolymer (PAtBA) crosslinked with polyethyleneimine (PEI) has been used successfully for various water shutoff applications. This paper will describe results from a sampling of over 200 jobs performed throughout the world, including the average results from over 90 jobs performed in one geographic location alone. In addition to "standard" matrix treatments, results will be shown for other types of treatment, including a design to plug annular communication and a combination of sealant and temporary gel in an openhole horizontal completion. In addition, laboratory data pertaining to work aimed at increasing the temperature limit of the system will be presented. The original upper placement temperature of the system was approximately 260°F. Data presented in this paper indicates the development of a retarder system that allows the upper placement temperature to be raised to at least 350°F.
Pressure Transient and Production Data Analysis for Hydraulic Fracture Treatment Evaluation
Authors: Ehlig-Economides C. A. , Valko P. , Dyashev I. S. , Economides M. J.
Published: December 2007

The Unified Fracture Design (UFD) concept provides a mechanism to determine the optimal hydraulic fracture design for a given amount of a selected proppant, while modern hydraulic fracture treatment execution offers the potential to achieve the optimal design. The proppant number is a ratio of the proppant permeability and proppant volume product to the formation permeability and reservoir volume product. The cost of the hydraulic fracture treatment is directly related to quality and quantity of proppant injected, and successful achievement of the optimal fracture treatment easily offsets this cost when appropriate economics is considered in the job design. Pressure transient and production data analysis are described in terms of fracture length and conductivity and do not provide measures of UFD parameters. The subject of this paper is the use of post treatment analysis to evaluate the effectiveness of the treatment in terms of dimensionless productivity index, dimensionless fracture conductivity, and the proppant number.

Results of this analysis show that when conventional buildup tests cannot provide the desired post-treatment analysis, in most cases, production data analysis can, and vice versa. The analysis will address both single phase oil and gas primary production and oil production under pressure maintenance or waterflood. Also, non-ideal fractures with height growth beyond the producing formation thickness and fracture skin will be considered. Field examples will illustrate the analysis. The importance of this analysis is paramount for operators trying to optimize high value hydraulic fracture treatments.
Gate Valve Drilling/Milling Operation on the North Slope, Alaska
Authors: Ogundare T. M. , Noreen T. , Olsen C. , Schrupp B. , Smith T. W.
Published: December 2007

Maintaining well control is a key component of well integrity. Keeping all the valves on the wellhead working and "moving" is important for well control. But ever so often due to calcium carbonate build up, exposure to extreme weather conditions, stem breaking as a result of corrosion and other causes there have been reported cases of valve malfunctioning.

Milling out a gate valve is a very tedious operation and could be risky if the proper well control and procedures are not put in place. To date there are not many documentations on this procedure. Experience indicates there are two typical methods of milling out a faulty gate valve.–Using a gate valve drilling/milling machine–Using a coiled tubing unit

Well A and B are both producing wells on the North Slope, Alaska. In well A it was discovered that the master valve would not close fully and the swab valve could not open from the closed position. Well B had a master valve that was damaged in the closed position. Well A's gate valve was milled out using the milling machine and well B's faulty valve was mill out using the coiled tubing unit.

The objectives of this paper are to examine these two methods of gate valve milling and the procedures of the operations. After drilling out the valve, fluid can be pumped down hole to kill the well or wireline tools can be run in the well to set back pressure valves and plugs in order to well control.

The risks that would be typical in a gate valve drilling operations will be examined. The risk analysis should be reviewed prior to the start of the job and documented.
Understanding a Reservoir: 3D Geological Modelling Using Scenario-Based Approach and Conventional Geostatistics, Onshore, UAE
Authors: Al Muhairi Layla Saleh , Ribeiro Maria Teresa , Dharmawan Agung , Al Neaimi Mohamed , Rodriguez-Gonzalez Jose Gregorio
Published: December 2007

A Geological Model was built and an Uncertainty Assessment approach was used to better understand the reservoir behaviour. Conceptual models were used to constrain the number of realizations, all of which are equi-probable solutions that honour both hard and soft data.

The primary inputs were core and log data from the wells. A Neural Net Facies and Rock Typing analysis was also performed. The data went through a data analysis process where the major uncertainties and scenarios were defined, and uncertainty trees created.

Two kinds of trends from regional and local information were introduced into the modeling process:

Depositional regional trends were assumed based on regional geological knowledge of the Facies distribution. Structural trends identified and applied to porosity Modeling.

The uncertainties considered were the structure, the fluid contacts, the continuity of the facies & RRTs, petrophysical properties and variograms ranges. The variability intrinsic of the stochastic methods was also accounted. Many cases were built and pre-ranked using the geological knowledge translated in a set of parameters to cover the uncertainty range.

Ranking of models was done by progressively analyzing the cases/ scenarios considered. Initially, inconsistent scenarios/ cases were discarded. In other words, those that did not comply with the data distribution expected and/or the spatial distribution and consistency with the conceptual geological models are discarded. The weight of each criterion in the decision that leads to abandon a particular case or scenario varies according to the variable modeled.

The final phase involved ranking the different models using body connectivity and volumetrics. The ranking was divided in sets where one variable was considered and others added progressively until all the variables were taken into account, including structure and fluid contacts uncertainty. The selected scenarios were then dynamically evaluated for well and development placement.
Adco Well Casing Cathodic Protection Project
Authors: Al Marzouqi Abdulla
Published: December 2007

Well Casing Corrosion is a serious threat to well integrity, Safety and environment with loss of asset & production shutdowns. In addition to the direct costs that result from corrosion like repairing corrosion leaks, reconditioning or replacing all operations of the system, contingent costs may be incurred.

Average cost of drilling a well USD 2,000,000 Average casing repair cost per well USD 85,000 Average no. of casing repair candidates per year 54 Nos. Total average annual cost of casing repair USD 4,500,000
Integrated Management System—Implementing QHSE Into Projects From Beginning to End
Authors: Iyer Srijayan N.
Published: December 2007

Increasingly, customers, regulatory bodies and the community are demanding that organisations demonstrate responsible environmental performance, provide a safe working environment, quality products and services, and where relevant effective food safety practices. An integrated management system allows businesses to manage their quality, safety, and environmental issues while avoiding unnecessary duplication.

This saves your organisation time, money and resources.

This paper identifies how an organisation can develop a management system in order to avoid duplication of policies, procedures and records, while meeting the requirements of their customers, regulatory bodies and the requirements of ISO 29001:2003 (QMS for the Oil & Gas Industry), ISO14001:2004:, and OHSAS 18001:1999.
Application of Intelligent Completions To Optimize Waterflood Process on a Mature North Sea Field: A Case Study
Authors: Ajayi A. , Konopczynski M. , Tesaker Ø.
Published: December 2007

This paper describes a dynamic reservoir modeling study and recommendations on the field implementation of intelligent well technology (IWT) on a mature North Sea field to quantify the benefit of using the technology for the redevelopment of the field. The study examines the impact of applying intelligent well technology to multiple production and injection wells to accelerate production, reduce well count, extend production plateau period and reduce well intervention.

The field is located in the North Sea with characteristics similar to the Brent field. Major hydrocarbon accumulation exists in four horizons. The field is mature with over 10 years of historical production data from waterflood operations.

The paper discusses issues relating to identification of the best application of IWT in the field and quantification of the potential gains from such application when compared to conventional completion systems. These include assessing the capability of the IWT to maximize oil production while managing water breakthrough and to commingle production from multiple sands while minimizing impact on reserves.

The study highlights potential pre- and post- installation issues with regard to the recommended intelligent well systems. This includes challenges and issues related to integration with existing facilities, well installation, crew preparation, system reliability, etc. The paper also discusses post installation well controls and practical guidance on measuring the predicted benefits from using the IWT.

The paper provides an overview of the application of intelligent well technology on a mature offshore field. The study estimated potential increase in oil recovery factor ranging from 0.48% to 6.1% of STOIIP over field life.
Avon Mod 5020—Technology Infusion Offers Benefits for Workhorse Gas Turbine
Authors: Hillman Gordon , Kendig Bryan , Taylor Dave
Published: December 2007

There are over 200 Rolls-Royce Avon gas turbines operating in industrial service throughout the Middle East Region. They have reliably served the region's oil & gas industry in power generation and mechanical drive applications for nearly forty years. Some operators of the Avon gas turbine have expressed a desire to produce more electrical or shaft power. Others have expressed interests to improve the engine's efficiency to offset higher fuel costs, and/or to allow longer periods of operation between major overhauls.

Rolls-Royce Energy Systems Inc, seeking to address operator demands, has developed the Mod 5020 uprate kit for the Avon gas turbine. The uprate kit provides between 6-8.5% additional power and 3-4% less fuel burn. When operated in a suitable derated mode, the mean time between overhaul is expected to increase by 20%.

This paper is a technical description of the Avon Mod 5020 product, as well as its development program.
Ultra Long-Offset ‘Subsea to Beach’ Controls Technology—Case Study Snohvit
Authors: Acworth Will
Published: December 2007

The Snøhvit project in the Barents Sea is a milestone in subsea oil and gas development, with a record breaking offset and all subsea facilities tied-back to shore.

The key elements of technology required to implement such a new development with a subsea Production Controls System qualified to operate over a distance of 220km are: Long-range communications with no repeatersLong-range supply of power at 3 kVHigh data rate requirementsHV electrical and fibre-optic wet-mating connectorsA cost effective main umbilicalDiverse backup strategies

This paper will focus on the technical achievements in executing this ultra-long offset subsea-to-beach project which is now nearing completion. The implementation of fibre-optic communications, subsea data routing, high voltage and power distribution technologies.Back-up communications on Power "COPS" systemThe Backup Intervention Control System (BUICS) designed for use in the event of main umbilical non-availability.
Successful Deployment of a New Stimulation Chemical, Post-Horizontal-Openhole Gravel Pack in Wells Drilled With Both Water-Based and Oil-Based Drill-In Fluid
Authors: Davidson E. , McMillan D. N. , Martin F. , Morton K. , Lenz R.
Published: December 2007

The Alba field in the central North Sea is an unconsolidated sandstone reservoir with an average permeability of around three darcies. Maximising productivity and extending completion life has been an evolving process throughout the life of this field. Recent practice is to drill the horizontal reservoir section using a water-based drill-in fluid (DIF) and complete with a circulating open-hole gravel pack (OHGP). One current option employs an oil-based DIF prior to gravel packing in brine. Both of these procedures have allowed higher off-take rates from these wells than previous completion practices.

New advances in the nature of delayed stimulation chemicals and the introduction of more effective additives (generating acid in situ downhole) made it of considerable interest to determine whether productivity could be further enhanced. One major obstacle to overcome was the uncertainty associated with the placement and uniform distribution of the stimulation treatment in a horizontal well, allowing the entire filter cake to be contacted and broken down successfully. This paper describes how the deployment problems were successfully circumvented.

A dual density treatment was employed in which both the upper and lower zones of the horizontal well-bore were targeted so that the filter cake on both the upper and lower surface in the hole would be contacted and attacked. Evidence will be provided indicating the placement resulted in an enhanced productivity index compared to conventional, non-stimulated completions. The new stimulation treatment was effective in wells drilled with either a water-based DIF or an oil-based DIF.
Field Implementation of "Squeeze Matrix-Access Reservoir-Targeting" Water Reduction System
Authors: Dalrymple Dwyann , Eoff Larry , Vasquez Julio
Published: December 2007

For many years, bullhead systems to reduce water production have received a great deal of attention from the oil- and gas-production industry. Water production becomes a major problem as fields mature, leading to higher levels of scale, greater lift requirements, more load on fluid-handling facilities, and increased environmental concerns. Because of the completion techniques used in many wells, protecting the hydrocarbon producing interval effectively during a water-control treatment is not always practical or cost-effective. Bullhead systems offer treatments that do not require zonal isolation and are designed to reduce water production with little or no reduction in oil or gas production.

Previous papers have discussed the laboratory development of a new water reduction system based on the use of a hydrophobically modified polymer. This paper will outline the field implementation of this squeeze-matrix access reservoir-targeting (SMART) water reduction system and will describe some of the successes (and failures) in its implementation. Even though bullhead systems such as this do not seal off water zones and, therefore, do not have the capability to completely stop water production, it will be demonstrated that SMART treatments can be economically attractive. While field-wide, multiwell treatments are attractive from the viewpoint of fully assessing system capabilities, single-well treatments can be beneficial to small and large operators alike.
Effects of Formation Damage and High-Velocity Flow on the Productivity of Slotted-Liner Completed Horizontal Wells
Authors: Tang Yula , Yildiz Turhan , Ozkan Erdal , Kelkar Mohan
Published: December 2007

Slotted-liner is a relatively simple and cost-effective well completion technique for horizontal wells. However, fluid flow into a slotted-liner completion is quite complicated due to three dimensional flow convergence around slots and limited open-to-flow areas. Furthermore, the compounded effects of formation damage and non-Darcy flow on the fluid flow towards slotted-liners must be considered in well completion design process.

This paper presents a comprehensive semi-analytical model for estimating the productivity of horizontal wells completed with slotted liners. The semi-analytical model is obtained by coupling the reservoir flow and wellbore flow equations. The model includes the additional pressure drops due to mechanical skin and non-Darcy effect. Additionally, the model could handle non-uniform flux, non-uniform skin distribution, and selective completion with blank pipes. Both oil well and gas wells are evaluated. For gas wells, the standard pseudo-functions are used. Detailed discussion of the effects of formation damage and non-Darcy flow is provided.

Results indicate that the productivity reduction because of formation damage is more significant for slotted-liner completion than the openhole completion due to increased pressure drop with flow convergence in the region with reduced permeability. Control of drilling damage ratio is more important than control of drilling damage radius. High slot density with low phasing angle helps to reduce the non-Darcy flow effect.
Enhanced Gas-Saturation Determination in Abu Dhabi Offshore Reservoirs Through Integrated Pulsed and Thermal Neutron Log Approach
Authors: Al Marzouqi Mariam , Al-Farisi Omar , Amer Mohammed Mostafa , Al-Habshi Ali , Lund Espin
Published: December 2007

Quantifying gas saturation in carbonate formations through cased logging remains an elusive objective. Unsolved gas saturation quantification in cased hole was always thought to be due to unknown or uncontrolled borehole completion, casing, cement, acidizing, perforation, invasion and/or formation damage. Several techniques have been developed in the past to correct for the cased-hole thermal neutrons logs in an attempt to normalize the data through laboratory experiments, correction charts or open hole computer processing of effective porosity (PHIE).

In Abu Dhabi offshore lower Cretaceous reservoirs, joint petrophysical & reservoir engineering efforts have shown that most of these automated corrections and/or normalizations are not capturing the real environmental changes from open-hole (OH) to cased-hole (CH). The reasons behind it are:

Open-hole neutron logs were not considered as the reference; instead, old technique uses PHIE (Effective Porosity). Casing and cement corrections are based on a homogenous isotropic model. There was no proper resolution matching between OH and CH and edge effect corrections applied to pulse neutron data.

Therefore, new technique is developed and presented in this paper; it is called "HYDGO" (Hydrocarbon Density Determination for Gas and Oil). This technique utilizes several back-to-back OH and CH log data information to carefully eliminate the CH environment effect. This is done by developing multi-variable-correction model that incorporates OH bulk density, water saturation, thermal neutron porosity and invasion. This procedure has led to the development of hydrocarbon density and gas saturation determination.
Abu Dhabi Heterogeneous Carbonate: New Upscaling Approach of Detailed 3D Geological Model
Authors: Elsaid Mohamed Elhami , Belgaied Adel , Al-Ginibi Faisal , Al-Farisi Omar
Published: December 2007

Through careful design of simulation model grids, and in order to overcome the computing limitations reasons, the main objective of the up-scaling process is to capture the flow characteristics, to retain the geological features and maintain the reservoir heterogeneity in both vertical and lateral directions in one of the major Carbonate oil field in Offshore Abu Dhabi, U.A.E.

The paper covers the geological modeling of the reservoir's complex heterogeneities, discusses and presents practical and efficient new method for upscaling from geological to reservoir model.

The challenge of Upscaling detailed 3D geological Model of multi-million-cell size into hundred thousands cell simulation model is well demonstrated.

In this regard, three upscaling approaches were adopted and validated against the roubst geological model. These methods are: (1) Up-layering visualization, the technique that provides reservoir engineers with optimal geologic layer-grouping schemes. (2) Geostatistical validation for the upscaled petrophysical data like Rock Types, Porosity, Permeability and Saturation attributes and (3) Validation through Streamline Simulation approach.

The use of this new upscaling approach ensures preservation and capturing of necessary geological details and reflects reservoir heterogeneity. Thus allowing realistic, representative and accurate reservoir simulation architecture to be used in Full Field Development plan scenarios. A feedback loop will be maintained between the simulation and geological

Thereby: validating and improving the geological model based on dynamic data.
Evolution of Sand Control Completion Techniques in the South Tapti Field
Authors: Holmes J. D. , Tolan M. P. , Hale C.
Published: December 2007

The stacked sands of the South Tapti field have presented completion challenges from field start-up in 1997 to the present-day. A large part of these challenges have been caused by reactive shales interbedding the sand bodies. This has had a persistent influence on the sandface completion design and, in particular, on the drilling and completion fluid systems.

The completion design has evolved from stacked cased hole gravel pack to open hole gravel pack designs. Non-gravel pack open hole designs are also being considered for the future to meet the challenges of drilling and completion at higher well angle. The field requires a mix of all these techniques to meet well objectives.
Laser Drilling Research and Application: An Update
Authors: Sinha Pankaj , Gour Aabhaas
Published: December 2007

The paper is an update to the current status of laser drilling technique - the first fundamental change to rotary drilling. We begin with a brief note on history of physical tests in 60's and 70's which were limited by the laser technology and low power available at that time. Seven lasers have been identified for potential use in the upstream oil industry. Each rock type has a set of optimal laser parameters to minimize specific energy as observed in the linear track tests. Current efforts are focused on underwater laser drilling.

Next, stress has been put on the basic scientific principles that can bring laser drilling within reach of an industry-supported prototype. Hence, the methods of delivering laser radiation and rock removal from wells drilled followed by parameters like feasibility, economics, benefits and environmental impact related to laser drilling have been discussed.

Laser drilling is found to be more efficient, cleaner way to drill and perforate wells through hard rock formations encountered at greater depths. The effects of the laser rock interaction on permeability have also been studied. Laser perforation resulted in permeability improvements. One of the major advantages of laser drilling is its potential to reduce drilling time. Lasers cut drilling time by not contacting the rock, eliminating the need to stop and replace a mechanical bit. Finally, we end with a discussion on the wider scope of laser technology for on-site tasks including cutting windows for side exiting casing or laterals, extended perforations that connect additional reservoir rock to the well bore, and removal of objects lost down hole that would normally require drill out or fishing operations.
Polyol Drilling Fluid: A Novel Solution To Curb Recurring Drilling and Completion Problems in Mature Sobhasan Field, Mehsana Asset, ONGC, India
Authors: Raza Khan M. S. , Pratap V. , Sharma K. C. , Anilkumar B. S. , Gupta A. K.
Published: December 2007

Sobhasan field is one of the oldest fields of Mehsana Asset, ONGC, India. Hydrocarbons are produced, mainly, from multi-layered reservoirs in Mehsana and Mandhali members of Kadi Formation. Being a mature field, the pressure of reservoirs has gone down to 0.7 MWE. These depleted reservoirs (0.7 MWE) are inter-bedded with pressurized shale sequences (1.18–1.20 MWE) and thick/fragile coal bands. With this type of pressure regimes, drilling of ‘S’ profile wells with conventional drilling fluids is a challenge. Recurrence of differential stuck-ups and coal-caving during drilling and ‘failure of logging’ during completion operations is a common feature. The paper presents how the application of tailor-made polyol drilling fluid along with improved drilling practices helped in mitigating the recurring complications.

The strategy to resolve such challenges required to either review the casing policy or change the profile of the well or bring in new drilling fluid system. First and second options were not feasible due to high heterogeneity in lithology and technical implications respectively. So the emphasis was given on the third option (i.e. use of KCl-PHPA-Polyol drilling fluid) along with improvement in drilling practices to resolve the prevailing problems. Extensive studies were carried out to formulate a tailor-made KCl-PHPA-Polyol drilling fluid.

The polyol drilling fluid was applied in two wells recently. Better drilling practices, while drilling coal sections, were adapted to avoid disturbance of coal sections. The apparent benefits are: saving of rig days, healthy bore hole, reduction in torque/drag, prevention of differential sticking, and smooth logging operations. The present paper is an endeavor to demonstrate how ‘polyol drilling fluid’ and ‘tailored drilling practices’ can complement each other in the completion of problematic ‘S’ profile wells smoothly. This proposal is an example of ‘Sharing Best Practices’.
Analysis of Hydrofracturing Efficiency
Authors: Vakhitova Aigul
Published: December 2007

Petroleum companies nowadays tend to increase oil production from low-permeability heterogeneous reservoirs. Commercial development of such difficult objects is possible with all modern stimulation methods involved including hydrofracturing. Decrease in flow friction near the wellbore and increase in filtration area as a result of fracturing lead to multiple increase in production well rates and injection well capacities. Besides recovery factor increases because of oil production from poor-drained zones and layers.

The purpose of this work was to estimate hydraulic fracturing efficiency by estimation of after fracturing well rate increase, by comparative analysis of well logging held before and after frac operation and by analyzing the well test. The task was to investigate factors of fracturing effectiveness. Also the principle of well selection for fracturing and their order in FDP was examined.

Data on Priobskoe and Krasnoleninskoe (Em-Egovskaya area) fields located in Western Siberia were used in this work.
Commissioning of Northeast Bab (NEB) Development Project
Authors: Saadawi Hisham
Published: December 2007

The North East Bab (NEB) Project has been recently commissioned by Abu Dhabi Company for Onshore Oil Operations (ADCO). The project is a grass root field development project to produce 110, 000 barrel per day. The project also includes facilities for water injection, high pressure gas injection as well as WAG. The oil production is from three separate oil fields; Al Dabbiya, Rumaitha and Shanayel.

Commissioning and start-up of the facilities were done by the company staff. This paper outlines the commissioning strategy adopted by the company and discusses the commissioning experience.
Integration of Microseismic Fracture Mapping Results With Numerical Fracture Network Production Modeling in the Barnett Shale
Authors: Mayerhofer M. J. , Lolon E. P. , Youngblood J. E. , Heinze J. R.
Published: December 2007

This paper presents the results of integrating microseismic fracture mapping with numerical production modeling of fracture networks in the Barnett shale. Microseismic fracture mapping has shown that hydraulic fracture treatments create large-scale fracture networks in the Barnett shale1–2. In this paper an approach is presented, where the fracture network measured with microseismic mapping is approximated with a numerical production simulator that discretely models the network structure in both vertical and horizontal wells.

The work includes a production history match of a vertical Barnett shale well, where the microseismic mapping results were directly used to approximate a fracture network in the reservoir simulator, resulting in an estimate of effective fracture network length, average fracture conductivity and effective drainage area. In addition, a parametric study for horizontal wells is presented to show how fracture network size and density, fracture conductivity, matrix permeability and gaps in the network affect well productivity. Simulations on the effect of fracture face damage along the network, the effect of non-darcy flow in the network, and tapered fracture network conductivity that decreases away from the well are also included. The numerical model was also used to simulate how a pressure buildup test would appear based on given fracture network properties, which could be a useful diagnostic to evaluate the effectiveness of the fracture network.

The results of this work illustrate how different fracture network characteristics impact well performance, which is critical for improving future horizontal well completion and fracturing strategies in the Barnett shale. This could include optimizing the number of fracture stages along the lateral, length of the lateral, treatment sizes, and perforation strategies as well as enhancing fracture network conductivity and the effectiveness of re-fracture treatments. The work also shows how microseismic mapping results can be integrated with production modeling, thereby providing a tool for more realistic infill drilling and well placement studies in the Barnett shale or similar types of reservoirs.
Dependence on Temperature, Pressure, and Salinity of the IFT and Relative Permeability Displacement Characteristics of CO2 Injected in Deep Saline Aquifers
Authors: Bennion D. B. , Bachu S.
Published: December 2007

Sequestration of CO2 in deep saline aquifers is a means with great potential for reducing emissions of this greenhouse gas produced from a wide range of industrial operations. The displacement characteristics of CO2 injected into deep saline aquifers are essential in that they control both the migration of CO2 and the available pore space in the reservoir at irreducible saturation conditions, yet very little information exists about these characteristics. This paper presents continuing results of a research study conducted by the authors to investigate the displacement characteristics of CO2-brine systems at reservoir conditions for cases specific to the Alberta basin and representative for intracratonic and foreland basins in North America. More specifically, the work reported here focuses on a controlled series of tests in which the effects of temperature, pressure and brine salinity were varied in a systematic manner to identify and quantify their effect on the interfacial tension between CO2 and equilibrium brine. The results indicate that the CO2-brine IFT decreases with increasing pressure, while increasing temperature and brine salinity have an opposite effect. These results were then extended under similar controlled conditions to consolidated porous media to investigate the effect of interfacial tension, as impacted by specific reservoir conditions of temperature, pressure and salinity, on the relative permeability character of CO2 displacing brine for a number of different interfacial tension conditions. The results are presented, and the significance with respect to the feasibility and optimization of CO2 sequestration in deep saline aquifers is discussed.
Evalution of Decrease in Productivity Indices of Production Wells in the Fields With Reservoirs Comprised of Highly Heteregeneus Carbonates
Authors: Dorfman M. B.
Published: December 2007

The productivity indices drop-versus-drawdown increase relationship has been fairly well known and described in the literature. This effect is most likely to be expected in the carbonate reservoirs with cavernous-fractured-matrix porosity and rock heterogeneity. It was observed to occur in the wells of Ardalin field and its satellites located in the north of the Timan-Pechora Oil and Gas Province during the well performance analysis. The discussed fields are highly prolific with the well flow rates as high as 1.500 m3 /day. The changes of productivity indices as an effect to increasing drawdown were not taken into account during well testing, modeling and production forecasts in the early phase of development. However, it becomes a necessity as the water production grows while the wells are converted from flowing to artificial lift with the electric submersible pumps, when the reservoir engineers need to achieve the optimal production rates and provide reliable production forecasts. Taking account of this factor will allow making the right choice of appropriate pumping equipment. The peak productivity of wells observed in the field appeared to be way below the original forecasts, which did not include the reservoir compressibility.
Application of New Fall-Off Test Interpretation Methodology to Fractured Water Injection Wells Offshore Sakhalin
Authors: van den Hoek P. J. , Volchkov D. , Burgos G. , Masfry R. A.
Published: December 2007

It is well established within the Industry that injection of (produced) water almost always takes place under fracturing conditions. Particularly when large volumes of very contaminated water are injected-either for voidage replacement or disposal-large fractures may be induced over time.

Unfortunately, not much work has been carried out to date to provide methodologies for predicting and measurement of the size of waterflood-induced fractures. This contrasts to the vast amount of work that has been done for stimulation (e.g. propped) fractures.

Injection Fall-Off (IFO) test analysis offers a cheap way to infer the dimensions of induced fractures from welltests. This paper presents a new methodology for IFO test analysis of fractured waterflood wells. This methodology derives the dimensions of induced fractures, and the extent to which these are contained to the target injection layer. Furthermore, the paper focuses on the application of this methodology to a waterflood offshore Sakhalin in the Russian far East.

The methodology is based on an exact solution to the fully transient elliptical fluid flow equation around a closing fracture with changing conductivity, face skin, and multiple reservoir mobility zones. It also captures the case that during closure the fracture generally shrinks from adjacent geological layers. It is demonstrated that the analyses based on the storage and linear flow regimes can be integrated into one analysis in order to reduce error bounds.

The method is applied to a number of examples in a water-flood offshore Sakhalin. Here, start-up of injection wells was accompanied by regular IFO testing in order to monitor fracture growth over time. The interpreted fracture dimensions were compared with predicted dimensions using a recently developed in-house waterflood fracture simulator. The fracture lengths as interpreted from IFO test analysis appeared to be systematically lower than the predicted ones, and a number of explanations for this difference are presented in the paper.
Application of the Fused Fault Block Technique to Fault Network Modeling
Authors: Hoffman Karen S. , Neave John W. , Nilsen Erik H. , Sarkisov Gennady
Published: December 2007

Fault network modeling of complexly faulted structures – those containing hundreds or thousands of faults – can be an extremely difficult and time-consuming process. A variety of methods exist to create the appropriate relationships between the faults, due to truncations, crossing, or offsets due to younger episodes of faulting, but each has limitations. Pillar or node-based techniques are often based on the concept that faults only exist where there are interpreted data; extensions of faults to intersections with other faults and/or truncation of erroneously crossing faults is a manual process, requiring the addition of nodes or pillars to the truncating surface. The location of the intersections can be dictated by the orientation of the pillars of the two faults, and so may not reflect the correct structure. An automatically generated binary tree, or hierarchy, can generate a reproducible fault network, where fault relationships can be stored. However, a binary tree cannot correctly handle all types of fault relationships and has particular difficulty in easily representing crossing faults.

Our technique uses a new concept of "fused" fault blocks. It begins with an approach somewhat similar to a binary tree, where each fault defines a hanging wall and foot wall side. However, our technique does not require faults that have an implicit relationship (that is, faults which do not intersect) to be explicitly defined in a tree. Fault intersections are determined from the active areas of the faults. Unlike a strict binary tree, fault relationships here can be modified at any time, as interpretation or data changes.

Truncations can be stored and re-used, making the fault network repeatable. The accuracy of the fault network, the flexibility of modeling, and the use of this network to create reservoir grids allows an entire asset team to work with a high-quality earth model.
Reducing Screenouts in High Permeability Formations, Novogodnee Field (Western Siberia)
Authors: Davidson B. M. , Faizullin I. , Kazykhanova N. , Gayfullin A. , Senchenko D.
Published: December 2007

The evolution of the fracture stimulation in the Novogodnee Field in Western Siberia is detailed in this paper. The target interval is the JV1 interval of the Jurassic formation. This is a highly productive interval producing at a typical pre-stimulation rate of approximately 70 ton/day (500 bbl/day) with a high volume of gas. Significant increases in the production rate can be achieved by the successful application of fracture stimulation. Unfortunately, this was not the initial case in the field because most of the fracture treatments screened-out early in the fracturing process.

Even though the initial fracture treatments did not achieve the designs results, they did yield important information. First, there were increases in production resulting from the fracture treatments, indicating there is significant potential of higher production from successfully performing fracture stimulation. Also diagnostic injections were performed prior to the main fracture treatment to measure the critical fracture parameters.

Therefore a project was initiated to perform a detailed analysis of these fracture treatments to understand the cause of the early screenouts. As a result of this study the fracture treatments were redesigned leading to successful completion of the fracture treatments. The proppant volumes successfully placed have been as high as 213 tons (470000 lbs) of proppant. This is a significant increase over the initial treatments that screened-out with an average proppant volume of36 tons (80000 lbs).

The resulting production increase from the successful treatments has been significant. The folds of increase in productivity have increased from 1.9 on the fracture treatments with the early screen-outs to an average on 3.1 folds of increase on the recent wells. The highest productivity increase was 3.4. These folds of increased productivity have resulted is the equivalent post-stimulation production rates increasing from 130 tons/day (950 bbl/day) to 220 tons/day (1600 bbl/day). Well J is an injection well as part of the pressure maintenance program. Following the fracture treatment the injection rate of fluid volume is equivalent to 1000 tons/day (7300 bbl/day). If the interval had not been fracture stimulated the rate would have been significantly less.