bluuebunny/crossref_metadata_2025 huggingface dataset:
An Intelligent Hydraulic Fracture Optimization Model: A New Tool to Stimulate Low Permeable Oil Reservoir
Authors: Rahman M. M. , Rahman M. K.
Published: December 2007

The increasing demand for hydraulic fracturing to stimulate low-permeable reservoirs has lead to the use of various fracture optimization techniques to find optimum values of controllable design parameters. In case of inappropriate values of these parameters, many unexpected complexities may arise during treatments that lead to high treatment cost and low productivity. While recognizing the role of incompatible fracturing fluids and inappropriate execution of treatments, the role of inappropriate treatment optimization is not well investigated. To avoid complexities, one needs to solve a constrained model to screen out potentially problematic designs with the aid of an intelligent optimization algorithm, in contrast to the widely-followed conventional approach of unconstrained parametric optimization. This paper presents an integrated constrained model for treatment optimization to maximize production. The Model has incorporated many design constraints based on hydraulic fracture mechanics and industry experience, and the global optimization scheme is driven by an intelligent moving object algorithm. The design constraints relate fracture geometry and its growth, surface operational parameters, non-dimensional fracture conductivity, proppant number and proppant fall rate in the fracture. Successful viscosity scheduling of the fracturing fluid is particularly influenced by power-law parameters and shear rate in the fracture, which can be controlled by fluid preparation and controlled injection. These parameters are included in the free design variables in optimization work for the first time. A combined objective function is formulated to maximize production while simultaneously minimizing the treatment cost, and trade-offs between these two conflicting design objectives have been investigated. While applied this model to a low permeable oil reservoir to demonstrate its merits, an optimum treatment designed by this model has offered an incremental production by 100% and a treatment cost saving by 20% of their initial cost. Sensitivity results of various parameters also indicate the implication of design other than optimum.
Two-Phase Relative Permeability Prediction: A Comparison of the Modified Brooks-Corey Methodology with a New Carman-Kozeny Based Flow Formulation
Authors: Behrenbruch P. , Goda H. M.
Published: December 2007

The prediction of relative permeability has been in the past and is currently a very active research area, with theoretical, experimental and empirical approaches under consideration. However, it is fair to say that the complexities of relative permeability have to date eluded researchers and practitioners alike, in that there is no universal formulation that is able to predict two-phase relative permeability for the wide range of rock and wettability characteristics observed. This paper presents a new, generalised formulation, one that is truly predictive, and compares the same with the industry standard - the modified Brooks-Corey (MBC) formulation.

The MBC formulation is perhaps the most widely used, practical method describing laboratory-derived relative permeability relationships in terms of simple power functions. The shortcomings of this formulation are that it has no real predictive capability and the relative contributions due to pore structure components as compared to variation in wettability cannot be resolved. The new two-phase flow formulation presented is based on a phenomenological approach related to the Carman-Kozeny equation, and is able to resolve the above mentioned shortcomings.

Included are several laboratory examples and the results of a comparison of the two formulations is presented. It is shown how the new formulation is able to predict "the curvature" of relative permeability curves when only the endpoints are known, duplicating observed behaviour from steady-state relative permeability experiments. Alternatively, if the endpoints can be derived, correlated or estimated with the use of more fundamental data, the entire prediction of relative permeability is possible.

In conclusion, the formulation presented is able to predict two-phase relative permeability under steady-state conditions, not just merely fit data. The second advantage of this method is that it is theoretically based and does not involve any fitting parameters but involves relatively simple analytical expressions.
Reducing Uncertainty Through Downhole Fluid Analysis: A Field Case Study
Authors: Muruais J. M. , Young A. A.
Published: December 2007

One of the challenges that operating companies face during any oil field development project is to deal with the uncertainty associated with the data acquired in the exploration and appraisal phases, which can be ultimately used to forecast reservoir behaviour, hydrocarbon recovery, and production. This particularly applies to marginal fields where uncertainties such as geology (static information) and reservoir drive mechanism (dynamic information) may impact significantly the estimation of reserves and result in the termination of the project during the appraisal phase.

The context of this case study is the appraisal phase in the development of two fields with heterogeneous, thin shaly sand sequences, where potential sand discontinuity exists. The fields are located in the Intra-Latrobe formations of the Gippsland Basin, offshore Australia. Accurate field description and reserves estimation was critical for the outcome of the full field development project. Logging-while-drilling logs, wireline logs and wireline formation tester pressure data, identified a number of potential hydraulically isolated hydrocarbon-bearing sands. During data acquisition, the degree of uncertainty associated with some of these intervals was perceived as significant for the estimation of oil in place and prediction of reservoir behaviour.

This uncertainty was addressed by a comprehensive wireline downhole fluid analysis (DFA) program consisting of multiple pumping stations over the reservoir intervals. The program conclusively identified multiple independent hydrocarbon-bearing sand intervals and assisted critical interpretation of the sand continuity particularly the semi-continuous distribution of fluid composition and gas-oil ratio versus depth. The DFA data was pre-processed in real time, enabling more accurate preliminary hydrocarbon volume estimation, as well as establishing with more confidence the perforating strategy over the main producing intervals.

For the first two wells of the field appraisal campaign, samples were recovered from all the hydrocarbon-bearing intervals and analyzed in the laboratory. The comparison between lab results and DFA provided a benchmark for optimizing the sampling programme with DFA for subsequent appraisal wells.
Portfolio Optimization: Systems vs. Sequential Approach
Authors: Al-Harthy M. H. , Khurana A. K.
Published: December 2007

Traditional investment decisions in the oil and gas industries ignore dependencies and interactions between parameters such as reserves, production and economics. In a previous paper1 we have shown that for a single project the system stochastic approach better captures the impact of dependencies and interactions among the components of decision parameters compared to the sequential approach and improves decision quality.

In this paper we build on the previous work and investigate the impact of system stochastic and sequential stochastic modeling on the portfolio efficient frontier. We use a stochastic integrated model, which captures uncertainty for a mix of five hypothetical offshore oil field development projects. The model combines reserves, production, capital and operating costs into an integrated probabilistic economic evaluation. The output of the stochastic model is used as input into the Markowitz Mean-Variance model and varying our company's participation level in the five projects to compute the efficient frontier.

The results show that the two approaches yield substantially different efficient frontiers. As expected the difference between the systems and sequential approach increases with increasing standard deviation of the portfolio NPV with the expected value of portfolio being greater in the systems approach. In our example, the difference in the computed expected NPV ranged from 8 % at lower level of risk to 15% at higher level.

In conclusion, the system approach is superior in capturing intra-project dependence and its impact on the portfolio level is significant compared to the sequential approach. Both the systems approach and the portfolio methodology complement each other in capturing both intra-project and inter-project dependence at the portfolio level.
Fracture Model for General Offshore Applications
Authors: Kaarstad E. , Aadnoy B. S.
Published: December 2007

The complexity of oil and gas wells has increased significantly the past decades. In addition to improved equipment, a better understanding of the subsurface environment is required to drill these wells efficiently.

Two modelling activities have been pursued in Norway the past decades: 1) Establishing a fracturing model for shallow penetration offshore, and 2) develop a fracture model for deepwater drilling.

Data from seabed investigations and from conductor and surface casings were collected and normalized for varying water depths. This model works well and has been used for many years. When deepwater drilling started in 1997 the same concept was applied. The results show that the same type of model applies also for deepwater drilling.

Wells from Norway, UK, the Gulf, Angola and Brazil have been analyzed. They show remarkably similar behaviour when the water depth is considered.

This paper brings this work further by presenting a generalized fracture model for relaxed depositional environments that works for all water depths. Normalization methods will be presented so fracture data can be converted to other water depths (serve as prognosis for new wells), based on rig floor elevation, water depth, differences in overburden stresses, and on mud properties.

Several field cases will be presented with water depths ranging from 380 m to 1350 m, demonstrating the wide applicability of the new model.

It will be shown that the generalized fracture model provides a good correlation with an error within a few percent.
New Gun-Hanger Design Provides Safety and Flexibility for High-Rate Gas Wells in North China Kela Field
Authors: Hales J. , Smith I. , Wah Kee Yong , Xun Liu Jian , Yong Li Ru , Qiu Liu Ming
Published: December 2007

Tarim Oil Company, a major producer in northwest China, operates the Kela II field in the remote province of Xinjiang. Their completion program required underbalanced perforating for several large-volume gas wells with estimated record breaking flow rates. To support the operational priorities on safety, reliability, and flexibility in the completions, options for perforating were limited to wireline-deployment and modular gun-hangar systems so that gun removal would be possible if any nonconformity occurred. To obtain the maximum well production after perforating, it was imperative that minimal wellbore damage occur. Killing the well was not a viable option since the reservoir properties in the Kela field are fluid sensitive. Therefore, killing the well after perforating underbalanced would increase near wellbore damage and produce a higher skin.

This paper will discuss the two wells completed in this field using a newly developed perforating method. There were four wells developed, but two were completed by another perforating service provider. The expected production from each well was ∼4 MMscf/d. Production from the two wells completed with the methods described in this paper exceeded expectations by 46% with a rate of 5.85 MMscf/d at full open choke with a 5 MPA drawdown. The production from the two other wells that were perforated using other methods fell short of expectations with rates of less than 4 MMscf/d.
Data Acquisition With Advanced Acoustic Telemetry Improves Operational Efficiency in Deep-water and Land-Well Testing—Case Histories
Authors: Azari M. , Salguero A. , Almanza E. , Kool H.
Published: December 2007

A new Acoustic Telemetry System (ATS) that obtains realtime bottomhole pressure and temperature data without the use of wireline has been introduced to the oilfield. Traditionally, wireline has been used to acquire bottomhole surface read-out (SRO) data in real time during well-test operations using either a wireline-deployed downhole inductive system or a download probe in close proximity to the transmitting device operations. The operational hazards possible when using wireline in deep water subsea safety systems have increased safety risks in certain applications.

This paper discusses a new system that uses acoustic telemetry and operates with either down-hole latching or with a download probe located in close proximity to the transmitting device. The system was designed for land rigs, offshore jack-up rigs, and deepwater floating rigs. In addition to wireless data transmission to surface, the system has downhole memory gauges that record data independent of the real-time SRO interval rates. The system is also capable of bi-directional acoustical communication, which allows commands to be sent from surface to operate downhole instruments.

The quality of data compares excellently with downhole memory gauge data. Other operational advantages of the system include the fact that 1) testing equipment can be in the well prior to firing the perforating guns, 2) reduced rig time can reduce operational costs, and 3) personnel and environmental safety are increased. In case of transmitting the data via the wall of the testing pipe, there is no need for a probe or latching device.

The two case histories, which are presented in this paper, will describe system use and will verify its advantages.
A Generic Solution to Bottomhole-Assembly Modeling
Authors: Wu M. , Chen D. C. -K.
Published: December 2007

This paper presents industry's first generic algorithm using Lubinski's equations for Bottom-Hole Assembly (BHA) modeling. The algorithm is designed to "self-structure" the BHA model by dividing complicated BHA configurations into independent modules and segments. Modules are bounded by two stabilizers where segments are bounded by BHA components such as stabilizers, bends, and cross-overs, etc. A recursive process is used to derive solutions for each of the segments and modules, one at a time, starting from the top of the BHA (tangential point) down to the bit. Only two unknowns (and two non-linear equations) are left when the recursive process reaches to the bit. The two unknowns are then solved by iteration. As a result, the entire process is robust and extremely computational efficient. The most significant advantage of the new algorithm is probably its accuracy as attributed to the use of closed-form equations. Field data has confirmed that the algorithm is more accurate than the commonly used finite-element based BHA programs especially for the steerable motor systems and rotary steerable systems.
The Feasibility Studies of Polymer Foam Flooding in Gudao Oilfield
Authors: Li Zhenquan , Zhou Guohua , Zhou Zongming
Published: December 2007

Gudao oil field is one of the major production areas in Shengli Field. After 20-year development, most of reservoirs are characterized by high water cut, poor sweep efficiency and inefficient oil recovery due to the high heterogeneity.

The goal of this paper is to present the results of laboratory and field studies of polymer foam flooding in Gudao oilfield. For polymer foam, the displacement medium is N2 mixed with surfactant as foaming agent and polyacrylamide. Polymer foam can increase the sweep efficiency and control gas mobility by selective gas blocking and high apparent viscosity. The experimental investigation studied the use of additives to enhance foam properties and the factors affecting blocking performance such as injection model, gas liquid ratio, and alternate slug, etc. The oil displacement experimental results showed that the previous bypassed low permeability areas in polymer flooding could be swept by polymer foam displacement, and thus increasing oil recovery.

The scaled-up laboratory data has been successfully applied in a field test. After 3 months of injecting polymer foam, the daily oil production increased from 75.1 t/d to 141.4 t/d, while water cut decreased from 93.9% to 88.1%. The above results demonstrate that enhanced foam flooding is a promising method for producing highly heterogeneous reservoirs and to improve the reservoir sweep efficiency after polymer flooding.
Results of Proactively Managing a Heavy-Oil Waterflood in South Oman Using Streamline-Based Simulation
Authors: Naguib M. , Sikaiti S. , Balushi H. , Barrio C. , Mahrooqi S. , Batycky R.
Published: December 2007

Streamline simulation is an ideal reservoir management tool for mature waterfloods since it can identify unswept reserves, quickly evaluate multiple forecast scenarios, and provides novel information like well-pair interactions. The identification of well-pair interactions is particularly useful as it allows for pattern surveillance, quantifying offset production with injection volumes, and identifying efficient vs inefficient areas of injection.

The Thuleilat heavy-oil field consists of 120 wells and is geologically complex with stacked reservoirs, multiple oil-water contacts, and numerous faults, making it difficult to identify well interactions and areas of unswept reserves. However, being a dead oil reservoir with the majority of production a result of injection, it is ideally suited for streamline simulation. Several opportunities were identified based on the streamline simulation. These opportunities, which generally apply to all waterfloods, could be divided into well rate target recommendations, pattern optimization, producer-injector conversions, and infill locations.

Pattern optimization opportunities resulted in a 10% gain in the offset oil producers. In one of the pattern optimization activities three water injectors were identified for injection rate increase, followed by optimization activities in the associated oil producers which resulted in a significant oil gain. Other pattern optimization activities were to close in high gross rate wells and diverting the flow toward offsets oil producers. One of the trials was to close-in one of the producers in the central area for one week, which resulted in a measurable oil gain in 3 offset oil producer wells. The second activity was closing another producer in the northern sector for two weeks which resulted in an oil gain in 5 offset oil producers. Further use of the streamline model includes the assessment of unswept reservoirs for infill locations and the estimation of water cuts for development locations.
Drilling Riser Alternative Repair Methods for Leaking Joint Seals Utilizing Pressure Activated Sealant Technology
Authors: Cary D. Neil , Groomer Vic
Published: December 2007

Since the inception of deep water operations, drilling riser seal component failures have been a persistent problem worldwide. Traditionally these failures have required that the drilling riser be pulled, the affected seals replaced and then the drilling riser re-installed; resulting in substantial rig down time and expense to the operators and service companies. Seal-Tite International has developed a unique array of pressure activated sealants able to withstand the high pressure and extreme temperature conditions associated with subsea drilling and production operations. The sealant is polymerized by the differential pressure created through the leak sight. The polymerization process only occurs in the sealant that passes through the leak sight; all other sealant remains liquid and can be circulated out of the well with no damage to any of the well components. Subsequent to extensive testing, pressure activated sealant technology was utilized to repair a leaking joint in a drilling riser choke line at approximately 4200 ft water depth in the Gulf of Mexico. The leak was repaired and the client was able to continue and complete drilling operations with no downtime. The riser was tested to operating pressure every three days for the duration of the drilling operation with no leaks observed.
Experimental Study of Effective Hole Cleaning Using "Sweeps" In Horizontal Wellbores
Authors: Valluri S. G. , Miska S. Z. , Ahmed R. , Yu M. , Takach N. E.
Published: December 2007

Drilling fluid "sweeps" are specific fluids specially formulated to transport cuttings that cannot be removed by ordinary drilling fluid circulation. There has been a lack of certainty of the "sweep" type selection in the field. Although they are in common use in vertical and deviated drilling operations, not much information is known regarding the use of "sweeps", especially in terms of "efficiency" of the "sweeps" and the specific hydraulics involved.

The effect of rheology of the "sweep" fluid on "sweep efficiency" has been investigated under low pressure ambient temperature (LPAT) and elevated temperature elevated pressure (EPET) conditions. The LPAT tests were conducted on a 90-ft-long transparent test section that consists of an 8″ ID casing and 4.5″ OD drill pipe. To investigate the effect of temperature on the "sweep efficiency", EPET experiments were conducted under simulated downhole conditions. The University of Tulsa Advanced Cutting Transport Facility (ACTF) flow loop (73-ft-long test section with annular geometry of 5.76″ × 3.5″) was used to simulate downhole conditions. Three types of sweep tests were conducted with six drilling fluids that have different rheological parameters.

LPAT test results are presented in terms of weight of cuttings removed from the annulus, measured cutting bed height and differential pressure. Results of EPET experiments are presented in terms of cuttings concentration in annulus and differential pressure.

Through the rigorous experimental work conducted, it has been identified that within the test conditions "high viscosity" "sweeps" in the absence of drill pipe rotation proved to be ineffective in bed erosion and cuttings removal. In addition to a higher flow rate, low concentrations of polymer, i.e. "less viscous sweep" and drill pipe rotation greatly improve "sweep efficiency". Finally, recommendations are made for practical field operations.
An Effective Horizontal Well Completion and Stimulation System
Authors: Seale R. , Athans J. , Themig D.
Published: December 2007

Over the last two decades many developments have enabled accelerated growth in horizontal drilling. Drilling has led the way, with current technology capable of drilling thousands of feet laterally through a hydrocarbon reservoir. Second, has been completion and stimulation advancements. Initially horizontal drilling was limited to naturally fractured reservoirs with simple open hole or slotted liner completions. This was due primarily to the ability of the reservoir to flow economically without the need for stimulation. Reservoirs requiring stimulation were not candidates for horizontal drilling. Developments in completion and stimulation technology specific for horizontal drilling have broadened the application range for the technology.

Until recently there have been two completion and stimulation option. The horizontal can be completed open hole, or with slotted or perforated liner. This has essentially negated any effective stimulation along the entire length of the horizontal wellbore. The second completion system requires cementing the production liner and running multiple isolation systems to effectively treat different sections of the wellbore. This requires multiple coiled tubing trips along with multiple rig up and rig down of the stimulation equipment involved. These multi-stage horizontal completions take weeks to complete at high cost and elevated risks. Ultimately, the high completion costs or the lack of production due to ineffective stimulation make many reservoirs uneconomical to exploit.

This paper will detail a new completion system which is run as part of the production liner, which does not require cementing and provides positive mechanical diversion at specified intervals, so fracturing and stimulations can be pumped effectively to their targeted zone. Details of the engineering design and testing will be specified, with elaboration on the applications and case histories were these systems have been successfully deployed. The case histories will detail the operational efficiencies of the system in conjunction with the enhanced production realized.
Research Study for Microbial Restoration of Methane Deposit with Subsurface CO2 Sequestration into Depleted Gas/Oil Fields
Authors: Fujiwara K. , Mukaidani T. , Kano S. , Hattori Y. , Maeda H. , Miyagawa Y. , Takabayashi K. , Okatsu K.
Published: December 2007

Research into the microbial restoration of methane deposits has been carried out since 2003. The objective of this research is to estimate the possibility of microbial restoration of methane deposits using subsurface sequestered CO2 and indigenous anaerobes in depleted oil and gas fields. The most important factors are the efficiency and velocity of methane conversion by indigenous anaerobes inhabiting a reservoir.

Fluid samples (producing oil and water) from gas and oil fields in Japan were collected and analyzed in order to clarify the existence and survivability of indigenous hydrogen- and methane-producing anaerobes under severe reservoir conditions (high temperature and high pressure). PCR-DGGE analysis, a molecular biology method, was applied to reservoir samples such as reservoir brine, crude oil and producing water from the gas/oil fields. Some hydrogen-producing thermophilic bacteria (HPTB) and methane-producing thermophilic archaea (MPTA) which participate in the microbial restoration of natural gas were detected at the DNA level in some of the samples. Isolation of HPTB and MPTA was also attempted individually, and two strains of HPTB and one strain of methanogen were successfully separated.

Subsequent to these findings, accelerated hydrogen- and methane-producing experiments, using glucose as a carbon source, have been conducted at the laboratory level to estimate the potential for microbial methane production under actual reservoir pressure and temperature (5MPa, 50°C) and the rock pore as micro culture space. Experiments, using the isolates described above and active anaerobes which were not isolated from the reservoir brine, indicated that microbial hydrogen- and methane-producing efficiency and velocity are relatively high even in various reservoir conditions. Furthermore, if a suitable and economical carbon source is available, depleted oil reservoirs are potentially good candidates to become subsurface microbial reactors, using hydrogen- and methane-producing indigenous anaerobes containing HPTB and MPTA to convert injected CO2 into methane.
Engineered Cement Set Control Additive—Solution for a Long Standing Cementing Challenge
Authors: Moradi Sara , Zonzee Peter , Sandhu Depinder , Elarda Hussein , Jain Bipin , Salazar Jose
Published: December 2007

Cementing long zones with a single slurry system is a very challenging problem that has been known in the industry for many years. The main difficulty is related to the large temperature differential between the bottom and the top of the long cement column. The cement slurry is typically designed to have a thickening time to allow placement at the bottom hole circulating temperature. However, the same slurry when exposed to the much lower temperature that exist at the top of the cement column may not set for several days. This can lead to long waiting on cement resulting in rig non productive time or in certain cases can lead to well integrity problems.

Another known problem in the industry is setting of cement plugs in an environment where the bottom hole temperature is not well known. This scenario may exist while setting unplanned kickoff plugs or plug and abandonment of wells. The thickening time of slurries retarded with conventional additives are sensitive to temperature and therefore uncertainties in bottom hole temperature may lead to excessive setting time or premature setting, both of which can be costly.

A new generation of engineered cement set control (ECSC) additive has been developed to resolve the problems mentioned above. The ECSC additive provides thickening times that are almost independent of temperature thus allowing efficient and reliable cementing of long cement columns, where there is a large temperature differential between the top and the bottom. The ECSC additive will also minimize setting problems in situations where the bottom hole circulating temperature is not known accurately.

This paper presents the results of a successful field application of the ECSC additive to cement long casing sections in fields in the Middle East. The well designs require the reliable isolation of long casing/liner sections in order to safeguard well integrity and meet well construction objectives. Field implementation, results including logs from the wells are presented.
New Parallel Algorithm for Multiple History-Matched Realizations
Authors: Zubarev D. , Kelkar M.
Published: December 2007

Correct prediction of reservoir performance is an important issue for future reservoir development and exploration planning. This leads to the problem of accurate estimation of the rock and fluid properties used in construction of reservoir model. Usually, prior reservoir models are built by means of geostatistical algorithms and static information obtained from different sources and then adjusted for better production history matching. However, in some cases, static data can be very sparse and insufficient or misleading, for meaningful prior model construction. Under this scenario, adjusting of prior model would lead to a local minimum in automatic history matching algorithms and hence we will obtain results which may not be meaningful.

This paper presents a new methodology for Parallel Production data Processing. It assumes limited prior knowledge about static information and emphasizes the importance of production data.

This methodology begins with several initial models which represent large amount of uncertainty in prior models. The method goes through a process of cyclic parallel adjustment of multiple reservoir models and reliable information gathering for further models improvements. The algorithm seeks common trends developed in the prior models as a result of partial incorporation of production data. Every generation of multiple models is adjusted by means of gradient-based automatic history matching technique. By using common trends gathered from prior models, new set of solutions (alternate realizations) are proposed.

Generalized Changes Map (GCM) is the main source of information in this method. It provides the trend of common changes for all the models and serves as a basis of reliable parameters and spatial relationship selection. GCM captures two types of information: maximum changes occurred in prior model due to integration of production data, and convergence of values towards a common value in multiple models. These parameters form Generalized Distribution Map (GDM) and used as a conditional data for construction of a new generation of models.

Procedures of models adjustment, parameters selection, and models construction are continued till desired level of convergence in objective function is reached. The final product of the process is the multiple realizations which are history matched. The method is validated using some synthetic cases as well as PUNQ S3 model.
New Device for Drilling in Deepwater Under Semisubmersible: ABS unit
Authors: Guo Yongfeng , Ji Shaojun , Ye Aijie
Published: December 2007

There will be a big marketing for drilling in deepwater in the world. But there are few drilling vessels or platforms to suit to drilling in deepwater or super deepwater in international. COSL (China oilfield Services Ltd.) has some semi-submersible platforms and they are only suit to operate lessen to 500 meters of water depth. It become a difficulty for the company how to enter deepwater drilling market in time according to its condition of equipment? COSL noticed a new concept of deepwater drilling from a Norway’s company, and it means that some device might be fabricated, which may be matched with semi-submersible platform to drill in deepwater, operating depth about 500 m to 1500m. The concept name is Artificial Buoyancy Seabed (ABS). Its main principle is to set a tank of buoyancy under 300 m under sea level, which is located the center of bottom of the platform. The device utilizes the buoyancy force of the tank of column to support weight of BOP, so BOP will set in short distance from the face of sea. The result of using the device is that operation in deepwater will be the same as sallow water. It will improve the capability of the semi-submersible if ABS device would be used when drilling, which could increase the depth of water of operation, from 457 m to almost 1500 m in the offshore. It is very difference between shallow and deep sea that devices testing before operating in formal. In shallow sea, the device could be used directly after designed in primary. In contrary, the device of the deepwater will be used through a lot of testing and simulations because it is very expense that cost of operation in a day. The researchers and engineers would guarantee the device should be good properties and performances before it was used in the practice of the offshore. Since June 2004, COSL has carried out a series of item of the researches, experiments, and tests for the device, including to 9 experiments in some institutes in China and Norway, to proven its properties. The work correlative the device had been finished by cooperation both Chinese and Norwegian experts. This paper describes the procedure of work proven. The test in preliminary had been proven that the design of the device is reasonable, and COSL will do the first trial well in South China Sea at the end of 2006 or the beginning of 2007. Fig. 1Principle of concept of ABS
Training—Maximising the Human Asset
Authors: Delve Ken
Published: December 2007

Description of Material

The three core areas of Risk Management, Operations, and Health and Safety rely on the identification, development and maintenance of appropriate knowledge, skills and attitudes (KSA). These are encapsulated in the Training Matrix, a result of Instructional Systems Design (ISD). This paper examines the concepts of ISD in the creation of an appropriate Training Matrix.

Application

All organisations, especially those with high-risk or technology-centric elements, rely on the efficiency and effectiveness of their personnel – the Human Asset. The required competencies and standards can only be achieved, maintained and assessed through the application of KSA-related ISD. In addition to the KSA, the Training Matrix also provides processes and procedures for:

Through-career development of personnel. Personnel specification to assist recruitment, promotion and retention. Quality assurance through validation. Cost-effectiveness through evaluation.

In an industry that uses contract staff it is essential that the required KSA can be mapped across to the offered KSA; the Training Matrix includes methodologies for this by defining the job performance requirements.

Significance of Subject Matter

Training is at the core of all other activities. Training is resource-heavy (time and money) and it is essential that it is effective and efficient. It is vital that training is relevant and based on a Training Matrix using ISD. Training is the only way to ensure effective Health and Safety and to assist in mitigation of risk. Training ensures maximum development and utilization of that core asset – personnel.
Debottlenecking and Expansion of Upper Zakum GTP Plant at Zadco
Authors: Bhatia Sanjay , Fiaz Muhammed
Published: December 2007

The Upper Zakum (UZ) long term field development plans in order to achieve higher oil production within a short time frame poses enormous challenges to ZADCO in terms of reservoir management and expansion of its offshore surface facilities.

The produced gas is expected to increase due to higher oil production and anticipated gas breakthrough as a result of ongoing gas injection. ZADCO has initiated the initial phase of its expansion plans with de-bottlenecking and expansion of its gas compression, primary treatment and export pipeline facilities at Upper Zakum Central Complex (UZCC). The project is mainly brown field in nature wherein the optimization and full utilization of available capacity and available footprints are of prime importance. In addition as the total oil production is dependent on the gas handling facilities, the project strategy must ensure minimum interruption of the production during execution of the project.

ZADCO follows Value Assurance Process (VAP) which has different stages. The VAP stages are IDENTIFY, ASSESS, SELECT, DEFINE & EXECUTE.

The UZ GTP Expansion project was initiated in year 2004 and till date IDENTIFY, ASESSS and SELECT stages has been completed. The SELECT stage which is FEED design has commenced this year. The Project is scheduled to be completed by 4 Q 2010.

The project will enhance the current gas handling capacity of 125 MMSCFD to 230 MMSCFD by end of year 2010.

During the SELECT stage conceptual engineering, several studies were carried out through a reputed consultant and other specialist companies.

The following major studies were carried out during the conceptual engineering studies.

1.0 Reliability, Availability & Maintainability (RAM) Study 2.0 Computational Fluid Dynamics (CFD) 3.0 Process Study Process Simulations Exchanger Modeling with HTRI / XVib for higher capacity Flare Rationalization Fuel gas system adequacy checks Cooling Water adequacy check Pipeline hydraulic 4.0 Detailed Structural Study 5.0 Electrical System Modeling 6.0 Constructability study by EPC contractor. 7.0 Alternative technology evaluation. 8.0 QRA of UZ GTP plant. 9.0 Identificati of critical tie-in points. 10.0 Project Health, Safety & Environmental Review

Based on the proactive approach, critical issues which are likely to impact the project in future and could lead to production loss or have schedule and cost impact were carried out at an early stage of the project life cycle. This approach has enabled the project team to evaluate and focus on key critical areas during FEED and EPC stages of the project.

The conclusions and findings of the studies carried out during the conceptual stage have increased the stakeholder's confidence in ZADCO achieving the desired objectives and goals.
Strategic-Based Project Organization of Field-Development Activities
Authors: Al Jarwan Ali , Martin Wallace W. (Bill) , Walters John , Smith Richard , Al Kayoumi Qasem , Al Rougha Hamad Bu
Published: December 2007

Projected demands for oil and gas in the near term provide E&P companies with confidence to engage in aggressive field development expansions of production capacity over the next 10 years. Upper Zakum is a giant offshore field that has been in production since 1982. The strategic target for further development is to increase plateau production rate by 50% within the next 10 years while maintaining industry-best-practice reservoir management techniques and shareholder's economic guidelines.

Like most existing carbonate fields in the Gulf Region this aggressive rate of field development will encounter challenges related to reservoir management and facility capacity uncertainties. The challenges require both organizational and technological responses in many areas and at multiple levels.

The aggressiveness of strategic production goals demands that the technological and organizational issues be viewed in an integrated way that aligns and focuses competency requirements, work processes and technology implementation with strategic targets. In practice this requires that organizational structure must support the technological requirements for fully integrated multidisciplinary work processes.

The presentation will describe the detailed organizational development processes used by the Upper Zakum Field Development Department and the resulting project-based organization model chosen for implementation.
Maximizing Use of Well Log Acoustic Data To Define Seismic Attributes Leading to Better Development of a Mature Cretaceous Field in Abu Dhabi
Authors: Srivastava Ashok , Chakravorty Sandeep , Malik Kashif , El Wazeer Fathy , Boekholt Martin
Published: December 2007

Cretaceous reservoirs are under production in one of the largest Hydrocarbon accumulations in the UAE since 1963, using primary and secondary recovery mechanisms. More than 700 boreholes penetrated the main reservoirs, and an extremely high-quality 3D seismic dataset was recently acquired and processed. Conventional seismic interpretation and analysis, including inversion, was finalized and resulted in new insights in structure, rock and fluid properties.

As the excellent quality of the seismic offers the unique opportunity to study a Middle East Carbonate reservoir after 40 years of production at an unmatched resolution, the goal is to extract even more information regarding fluid types and fluid movement in this field, using advanced seismic methods combined with high-spec well information.

In light of the above, advanced sonic processing for different reservoir zones overlying cap rock and overburden formations up to surface was carried out in eighteen wells. Important rock properties derived from this study were linked to seismic data and VSP information. The key attributes that were obtained from the processing of the acoustic data were Shear Anisotropy, Vp/Vs ratio and Uni-axial compressive strength (UCS). Dispersion analysis was done to verify the source of the shear Anisotropy. All these attributes obtained from the log data serve as key control points for advanced seismic analysis for mapping rock and fluid properties.

The result of the described workflow of using multi-well acoustic attributes is the key input for advanced seismic studies including AVO analysis, azimuthal seismic data analysis and shear-wave studies. The ultimate goal is to allow more accurate reservoir model description for optimisation of the field development and production management.
Identification of Key Fracture Effects on Fluid Flow and Iterative Approach for Effective Permeability Modeling of a Matrix-Dominated Carbonate Reservoir, Offshore Abu Dhabi
Authors: Shibasaki Toshiaki , Edwards Ewart , Qotb Mamdouh , Akatsuka Kazuhito
Published: December 2007

Modeling effective permeability in carbonate reservoirs is a challenge in many cases, especially in subtly-fractured matrix-property dominated reservoirs, where the presence of tectonic fractures and/or matrix-related high permeability streaks can considerably enhance the effective reservoir permeability. Small-scale faults and fractures, especially when located within ‘layers’, zones or ‘corridors’, can affect water movement in the reservoir: these can be identified from core and image log more readily than from seismic data. Often neglected, diffuse fractures concentrated in stratigraphically predictable ‘fractured layers’ at reservoir-dense contacts can play important roles in fluid flow in such reservoirs.

Permeabilities derived from well test data often do not match with thickness-weighted core permeability averages, therefore, core based permeability values need to be modified to match the well test data, applied according to the fracture susceptibility of the stratigraphic zonation of the reservoirs, which reflects a mechanical layering effect. Different data media are useful in determining the most applicable drivers, with respect to the different fracture styles present (‘fractured layers’, corridors & fault zones), e.g. curvature analysis of 3D seismic derived reservoir surfaces are effective indicators of possible sub-seismic scale fault zones or fold flexure structures, such lineaments defining water movement pathways in the reservoir. Lateral fracture density variation may relate to such reservoir surface attributes as an indirect indication of strain magnitude within the reservoir. Additionally, fracture density on a per foot basis, from core observations, can also represent a fracture contribution of effective permeability in the vertical profile. A conceptual model incorporating all three fracture styles summarizes the non-matrix fluid flow system present.

In this particular example, the characteristics of the reservoir are controlled by both matrix properties and fractures. Achieving realistic effective permeability, by integrating core- and seismic-based fault/fracture information is a complex process that requires successive iterations, which can be both time-consuming and laborious when giant fields are considered. The presentation illustrates an iterative workflow to integrate an existing geological model (i.e. matrix-dominated model) with the core fracture and seismic-based data to construct a reliable effective permeability model for the reservoir that best fits the dynamic data from the field.
Towards an Adco Real-Time Operations Centre (RTOC)
Authors: Gyllensten Asbjorn , Salem Adel , Coleman John , Ali Waheed , Youssef Fahd , Grayson Harold , Ragheb Omai , Russell Rick , Nabawy Sherif , Nair Rejeesh , Kalathingal Paul
Published: December 2007

When ADCO established the RTOC taskforce in July 2003, their vision was to have a center to run rigs like a large scale industrial process on a continuous basis 24 hours a day, 7 days a week. The objectives were to utilize new technology for transmitting data from our rigs to drive new ways of working to optimize the drilling process; Geo-steer difficult wells, update 3D Earth Models and visualize well progress in 3D for interactive decision making in Real Time. The feasibility of the RTOC project had to be demonstrated from facilities, staff resources and economic points of view. Commercial options available in the market were studied and a phased approach adopted.

In the first phase a real time data transmission capability was established. Following a Tender the potential vendors were evaluated technically and commercially and by mid 2005 all rigs were connected using Halliburton's INSITE™ software. Real time data transmission for mud logs and Logging While Drilling data from all vendors is now routine. Links have been established to our data evaluation platforms and 3D models.

The second phase focuses on defining software to enhance drilling performance and addressing staff issues related to 24/7 RTOC operation, finding the right balance between contract staff and ADCO staff and defining their training needs. "Intervention Protocols" also have to be agreed to define RTOC authority levels and when to refer to Drilling and Asset Team Management.

The final stage will cover the actual building of the RTOC, with workstations and data visualization screens for each rig in a centralized office lay-out. These new ways of working are expected to impact our business in a number of areas:

Identify potential hazards early. Enhance drilling efficiency with controlled cost. Improve well placement, quality and production capacity. Facilitate multidisciplinary decision making by placing Geoscientists, Drilling Staff, Petroleum Engineers and Service Company experts in one Integrated Team. Leverage manpower skills by having experienced staff cover several rigs. Improve safety by reducing personnel trips to well location. Provide easy access to lessons learned. Reduce cycle time for well proposals. Create an exciting, high profile environment for mentoring new intake staff.