bluuebunny/crossref_metadata_2025 huggingface dataset:
A 3-D Seismic Attribute-Based Reservoir Modelling of a Shallow Marine Carbonate Reservoir in West Africa
Authors: Tatsuo Shimatomo , Akira Kato , Hiroshi Fukagawa , Hiroki Arakawa
Published: December 2007

This paper presents a comprehensive reservoir study performed on a carbonate reservoir located offshore West Africa. Our study uses seismic information with pixel-based geostatistical techniques for the construction of fine-scale geological models. This field has eleven wells in the northern region. The information of the wells reveals that the field comprises some productive areas that have ensured commercial production, however others are less productive. In order to identify those productive areas in undeveloped region, especially southern portion of the reservoir, integration of the 3D seismic information into reservoir descriptions is necessary.

Our approach follows a four-step procedure. First, log data are correlated to core-measured porosity using the Alternating Conditional Expectation (ACE) algorithm. Second, more than 20 seismic attributes are investigated to specify relationships with well porosity. Third, fine-scale geological models are created based on well data and two seismic attributes with the Markov Bayes and cloud transform techniques. Finally, course-scale flow simulation models are generated by a scaleup technique for history matching purposes. An excellent history matching is achieved without any history match tunings. The prediction results obtained from fifty realizations indicate that the development of the southwestern portion is economically feasible.
Game Theory Application for Hydraulic Fracture Design
Authors: Mars Khasanov , Rinat Khabibullin
Published: December 2007

Today different methods of calculation and software packages to design well activities properly are at the disposal of petroleum engineers. This does not mean that decision-making in the oil and gas industry has turned into a routine. The most common problem petroleum engineers face is that reservoir parameters used in these calculations are unknown or unreliable. Thus, very often petroleum engineers have to make decisions under uncertainty.

In the past this problem was ignored, but today petroleum engineers increasingly consider uncertainty and risk analysis. From the viewpoint of data quality there are three criteria for making decisions [1]: Under fully deterministic conditions, when all data are known and complete;Under risky conditions, when random data can be described in terms of probability theory; the main criterion is the expectation value of the parameter that determines the quality of the decision;Under conditions of uncertainty, when it is difficult or impossible to classify data by their degree of significance and when it is impossible to apply probability theory methods, as distribution functions or other statistical parameters of these values are unknown.

This specification of terms is relevant as confusion of terms often causes ambiguity. Sometimes uncertainty analysis is conducted by the Monte-Carlo method applying series of random values of some parameters in compliance with given functions of probability distribution. It is obvious that the problem is reduced to risky conditions. In reality, as a rule, distribution functions are unknown, so we have the third type of conditions (under uncertainty) and the Monte Carlo method is not applicable.

In this case the decision-making problems are usually defined in terms of game theory, representing them as a "game with Nature". [1,2]. This paper considers different game criteria, which can be rather useful tools to increase the efficiency of decisions when managing oil and gas production processes under conditions of uncertainty. To make it more illustrative, a specific example of hydraulic fracturing design is used in the subsequent text.
Intelligent Asset Management: Successful Integration of Modelling Tools and Workflow Processes
Authors: Airlie C. J. , Lemanczyk Z. R.
Published: December 2007

The last decade has witnessed an almost universal shift of emphasis away from operator functional objectives towards the actual business performance of individual assets, which in turn is highly dependent on the day to day production environment and its evolution. Improvements in production data acquisition and data management technology are not always translated into real and quantifiable productivity gains, due to constraints in manpower, tools and expertise. This paper describes a methodology which can be used to address these issues through an integration of software technology and improved work processes.

A system has been developed which links on-line (realtime and near real-time) downhole, surface and corporate data to ensure that reservoir, well and facilities models are constantly monitored and updated to reflect actual operating conditions. With this "always current" encapsulation of the production system (between reservoir and delivery point) it is possible to perform a wide range of tasks to manage the asset performance: production optimization, facilities design and planning, production forecasting, allocation and loss management, etc.

The system integrates a number of existing software applications, and also streamlines the number of complex engineering tasks which are normally required. The system has been applied in a number of actual operational environments and the results of some of these applications are presented in this paper.

The main technical contributions described in this paper include: –A robust optimization technology which has been technically proven in a large number of field applications.–A workflow solution which automates production data transfer, manipulation and calibration to provide constantly updated well, facilities and network models.–Integration of the system with SCADA/DCS and corporate databases to shorten the field optimization cycle from months to hours.–Use of the technology for loss management, production forecasting and advanced surveillance.
"Why Can't I Just Start with a Map?" - Case Histories for Integrated Asset Management
Authors: Kozman Jess B.
Published: December 2007

Data sharing is an integral component of strategies to support critical decisions during the life of field value chain. Petroleum organizations face major challenges in the integration of legacy database systems to support an effective methodology for maximizing asset value. Case histories are presented that show effective integration of data, information, and knowledge in the asset value chain.
Field Optimization Tool for Maximizing Asset Value
Authors: Bailey William J. , Couët Benoît , Wilkinson David
Published: December 2007

A software tool is described that enables optimization for maximizing asset value, both with and without uncertainty. Modular architecture allows examination of different objective functions, optimization schemes and financial models. The method generates an efficient frontier that can be used for risk and decision analysis. The tool is demonstrated in the context of a field example optimizing for Net Present Value (NPV). Valuation of advanced completions is explored along with the returns gained from expanding surface gas handling facilities. The results clearly demonstrate the utility of such a tool for value-maximization in planning both near and long-term time horizons as well as providing the necessary foundation for maximizing asset value.
Developing A Model To Suit Life Cycle Costing Analysis For Assets In The Oil and Gas Industry
Authors: Vorarat Suparatchai , Al-Hajj Assem
Published: December 2007

This paper explores the application of LCC (Life Cycle Costing) concepts in the oil and gas industry. The paper details research into the development of a LCC model for using in SAP (System, Application and Products in Data Processing). Information held in the existing system in the oil and gas industry has been investigated in order to determine whether or not it is adequate to support LCC application for assets. The conceptual framework will develop the LCC technique as a tool to carry out costing analysis for new and existing systems. It will ensure that existing systems data are optimized for use in LCC applications and will investigate the feasibility of integrating the LCC model with existing systems. Based on this conceptual framework a LCC model will be developed.

The proposed system model provides a structural breakdown of cost (SBC) that can be applied to any asset at any level, such as super system, system, sub-system and equipment level in its lifecycle. The purpose of this SBC is to act as an aide memoir, as the starting point for developing a project/asset specific SBC that is tailored to the needs of a particular LCC requirement. The overview of SBC is provided to identify the data requirement for estimated cost element and provides a definition for cost element.

Consequently, if SAP-LCC is used for analysis at every, it is possible to identify the level that is the most significant in order to develop or reduce the cost in LCC at that level.
"State-of-the-Art" Integrated Studies Methodologies - An Historical Review
Authors: Breit Vernon S. , Dozzo Joe A.
Published: December 2007

An integrated reservoir study represents the one reservoir modeling technique available to a reservoir management team that incorporates ALL of the information available regarding a petroleum reservoir. As such, the integrated study has the potential to provide the team with the highest resolution most accurate description of their field that is currently available. However, that high resolution comes at the expense of a highly complex, data intensive process. This paper was an attempt to simplify and codify the complex process of performing an integrated reservoir study.

The paper presents an overview of the integrated reservoir modeling process including how that process has changed from the early days of reservoir simulation to the present day. Two models are presented that illustrate the study process for a 1980 time frame multi reservoir study and a 2002 time frame geostatistically based compositional reservoir model‥

Emphasis is placed on the changes in workflows from the early models -- simple mapping of properties and manual digitization of maps to simulation model grids -- to the more complex models of today -- with property distributions based on object modeling and geostatistical analysis to distribute reservoir properties.

Through the examples, the paper illustrates the point that reservoir studies have evolved from a time when the geologists and engineers often knew more about their reservoirs than the available modeling tools would allow them to implement in their models – dual porosity and flow across faults, for example – to the point where today we often have the modeling capability to model more complex phenomena than our knowledge of the reservoir may warrant – for example, object modeling with no data on the characteristics of lithofacies in our reservoir, or dual porosity flow models with no data on fracture spacing and distribution.
Integrating Soft Computing and Hard Computing For Production Performance Prediction of Low Permeability Reservoir
Authors: Yang Qingjun , Guan Zhenliang , Gao Yufu , Jiang Hongxia , Musa Tagwa A. , Tian Genlin
Published: December 2007

Development of low permeability reservoir is very different from that of normal reservoir. Complicated geological and engineering factors conspire to affect wells production performance. Moreover, these factors vary with the development strategies for different low permeability reservoirs. It is difficult to accurately describe these factors and further predict its production performance. This paper presents a new methodology integrating soft computing and hard computing to predict production performance of low permeability reservoir. Integration of data and knowledge is used for soft computing. Firstly, the knowledge about fluid flow is extracted by numerical simulation (a conventional hard computing technology). Then the knowledge together with corresponding data is input to model production performance by neural network (a popular soft computing technology). Lastly, the trained models are used to predict the production performance. This method is proved to be effective for low permeability reservoir.
A Novel Model for Permeability Prediction in Uncored Wells
Authors: Shokir E. M. El -M.
Published: December 2007

Fuzzy model is applied for permeability estimation in heterogeneous oil reservoirs using core porosity and gamma ray logs. Also, the basic concepts of fuzzy model is described, and how to use the constructed model to analyze and interpret the results. Fuzzy logic approach is used to represent a nonlinear relationship as a smooth concatenation of local linear submodels. The partitioning of the input space into fuzzy regions, represented by the individual rules, is obtained through fuzzy clustering. The results from the fuzzy model shows that it is not only accurate but also provides some insight into the nonlinear relationship represented by the model. Whereas, the results of the blind test developed a good agreement between the measured core permeability and the output of the fuzzy model.
Inter-reservoir Communication Detection via Pressure Transient Analysis: Integrated Approach
Authors: Al-Obaid Rashid , Bin Akresh Saud , Al-Ajaji Abdulaziz
Published: December 2007

This paper presents a successful integration of pressure transient tests, production, and seismic data to detect inter- reservoir communication between Hanifa and Arab-D reservoirs in the southern dome of Abqaiq field in Saudi Arabia.

Even though Hanifa and Arab-D reservoirs are separated by about 300 feet of impermeable Carbonates, the two reservoirs are in pressure-fluid communication through conductive faults/fractures in the heavily faulted/fractured area of Abqaiq field.

Late time pressure anomalies on the log-log plots were observed on several field examples of transient tests in Hanifa reservoir and some were interpreted as external effects of pressure support from the communicating Arab-D reservoir. Simulation modeling was used to further analyze such pressure responses.

Better reservoir management decisions and more focused development strategies can be achieved through the utilization of the quantitative pressure transient analysis of those tests.
To Improve Benefits by Injection Well Treatment
Authors: Tian Genlin , Tao Cheng , Qu Renwei , He Chang , Deng Jianjiang , Yang Qingjun
Published: December 2007

In this paper, development of a new well treatment method using in situ gelation as well as the pilot test have been presented. The result of the pilot test demonstrated good success in both technical and economic aspects.

For mature oilfields, water cut is normally very high. East part of Shenli oilfield in China is in such category. Water cut of most wells are high than 90%. Some of them are even higher than 95%. That means water flooding efficiency is very lower. Because of employment and economic problems, such oilfield must still keep on operation. In some regions, polymer flooding has been conducted. But it breaks through very quickly. From the break through and other diagnose, it is known that after long time of water flooding, the heterogeneous of the reservoir has been increased, even there are big channels between injection wells and production wells. In order to improve oil recovery in such reservoirs, a injection modification technique has been developed. This method is aimed to shut off big channel near injection wells. By this method, different chemicals were mixed together on the well location. The solution has low viscosity near as injected water. Such solution is pumped into the reservoir by removable pump and close the well 48 hrs for reaction. After reaction, such chemical solution became very strong gel filled in the pores of reservoir. Because during the time of injection, it flew into big channel first. After reaction, big channels has been shut off.

In a pilot test project, 14 injection wells have been treated with this injection modification technique. Reduction of water cut and increase of pressure indicate a good result. It also presented a very good economic benefit for mature oilfield. In this project, the chemical investment was US$. 335,400. Research cost was US$ 96385. Labour cost was US$ 34700.

The total cost was US$ 335422. Increased oil was 34300 Ton. With price of 1250 RMB/t and cost of 443 RMB, the benefit was 24896100 RMB, eg US$ 3 Mill.. From this can be seen that suitable well treatment is very important to mature oilfield. And it can also have obvious benefit.
Behavior of Water Cresting and Production Performance of Horizontal Well in Bottom Water Drive Reservoir: A Scaled Model Study
Authors: Wibowo W. , Permadi P. , Mardisewojo P. , Sukarno P.
Published: December 2007

Although application of horizontal well technology is categorized as a relatively new and expensive but it has been proven more effective and efficient in producing oil. However, the production rate strategy to obtain optimal result has not been well developed due to the difficulties to identify the influence and interaction of forces related to fluid flow mechanisms in reservoir. Particularly for oil reservoir with bottom water drive, the movement of water-oil contact/interface in a reservoir is strongly affected by interaction of the acting forces, such as: viscous force, gravity force and capillary force.

The main objective of this research is to study and investigate the influence of the forces interaction on production performance of the horizontal well producing oil from bottom water drive reservoir. For this purpose, a physical scaled model has been successfully constructed to simulate the prooduction performance. Scaling down and construction of the model are performed by using dimensional analysis.

Results show that the interaction of the forces in the reservoir strongly affects the well production, in which the production performance increases as the ratio of gravity to viscous forces increases for all cases examined. Meanwhile, the changing of capillary force, which was believed by several researchers that it has no pronounced effect to the fluid flow mechanism in the reservoir, shows significant effect to the production performance of the well. The influence of reduced capillary forces in reservoir will enhance the well production performance. Consequently, in term of the ratio of gravity to capillary force, an increase in the ratio tends to improve the oil recovery.
How 50 Million Tons Annual Production Has Been Maintained For 27 Years In Daqing Oilfield ---- A Successful Story
Authors: Yupu Wang , He Liu
Published: December 2007

The paper introduces oil production engineering series for heterogeneous, multilayer sandstone oilfield in the basis of separate zone production in the four development phases including production and stable production. The technologies provide technical means for realizing "Three-changes" of oilfield development, make an important contribution for keeping stable production of 50 million tons for 27 years in heterogeneous, multilayer sandstone oilfield. The development process and several technologies for different development phase are introduced in the paper.
Weighing Investment Decisions Through Project Economics and Optionality
Authors: Biswas Deepankar
Published: December 2007

Uncertainty resolution in recovery driving factors is a crucial issue in oil and gas exploration and exploitation activities. One such application is to select field candidates for development in the midst of several stochastic variables e.g. recoverable reserves, production rates, gas/oil price, discount rates etc. Unfortunately, the cashflows from investments tend to be stretched out in several years. Traditionally, to measure such inherent potential risks, engineering analysis is performed along with project economics. Engineering analysis builds confidence around recovery factors whereas the economic analysis justifies the returns through NPV and IRR computation. One implicit yet critical behavior, however, is often neglected. Investments tend to have embedded flexibilities, i.e. they are not always now or never type, which can be valued as flexible decisions via the theories available for financial options mathematics1,2. This paper investigates the application of financial mathematics to determine viability of a tight gas reservoir as an investment candidate and presents some interesting results dictated by intrinsic optionality.

Real options (RO) have gained increasing popularity in the oil and gas community in the recent past3-6. These applications employ analytic solutions of Black-Scholes type partial differential equation (PDE) available in the literature7-9 which are usually limited to cases of relatively simple payoff structure, exercise strategy, lower dimensions etc. However, most realistic cases, at the very least, will have complex payoff structure e.g. cascading cashflows in the example considered in this paper. Moreover, these options can be exercised anytime during the life of the project i.e. American type options. To accurately and rigorously compute option values in such cases one has to resort to suitable numerical approach to solve the PDE along with appropriate, complex boundary conditions.

In this paper, we prescribe one such technique, namely Implicit Mulitgrid Finite Difference (IMFD) to asses a two well pilot development program. Based on a previous engineering study, stochastic driving factors for the investment are determined. The investment is then crafted in a RO framework. Representative PDE is solved with imposed boundary conditions. Two different scenarios are considered and results discussed. Finally, exercise boundaries are forecasted above which, at a given time in the course of the project life, it is beneficial to exercise the option (in this example drill the development well) instead of waiting for a future exercise.
Hydraulic Flow Units Resolve Reservoir Description Challenges in a Siberian Oil Field
Authors: Svirsky Dmitry , Ryazanov Andrey , Pankov Michael , Corbett Patrick WM , Posysoev Andrey
Published: December 2007

The paper describes results of a petrophysical study aimed to improve reservoir description of a complex oil reservoir located in Western-Siberia, Russia. The K-field was put on production in 1998. The reservoir rocks were deposited in a sand-rich deltaic environment, that implies reasonably good lateral sand bodies continuity. Additionally, no evident continuous faults were seen by 3D seismic survey. However, recent field development has revealed far more complex reservoir compartmentalization and heterogeneity, than it was supposed at the exploration stage. A considerable variation of oil-water contact was encountered and large discrepancy was observed between log predicted and observed well productivity. Additionally core experiments demonstrated poor correlation between porosity and permeability with two orders of magnitude permeability variation at similar porosity values.

The hydraulic flow unit (HFU) approach is used in the present study as an integrating tool for petrophysical description of the reservoir. First, we start from a rock type classification based on core data to pick out major HFU constituting the reservoir. We employ combination of routine and special core analysis data to work out a resulting rock type classification for the studied field. Along with description of the HFU classification, we present the underlying geological reasons which control FZI variation for K-field reservoir. Based on geological and physical background we select relevant logs types related to FZI and propose simple regression approach of for prediction of FZI using gamma-ray and effective porosity log readings. Predictive capabilities of proposed regression approach is compared with more complex statistical techniques and we show that regression approach have reasonable accuracy of predicted FZI comparable to Bayesian inference and artificial neural network methods.

Then we use HFU distributions obtained for each logged well along with classified capillary pressure data for calculation of synthetic water saturation logs and estimation of the free water level (FWL) depth. The estimated FWL data supplemented with seismic information about possible discontinuities and faulting zones are used to update reservoir compartmentalization scheme and to delineate pay zones.

The 3D spatial distribution of the HFU is obtained using geostatistical modeling techniques and integrated into the geological reservoir model to define the porosity-permeability relationships. Additionally, HFU are used in the dynamic reservoir model to assign regions of relative permeability and capillary pressure functions.

The above described simple engineering application of the hydraulic flow units approach allowed us to construct an improved reservoir model and delineate a new probable pay zones, what lead to an increase of estimated oil in place by 70 %.
Keeping Abreast of New Technology Enhances Asset Value - Experience in Romanovskoe Oilfield, Western Siberia
Authors: Nor-Azlan N. , Aker G. H. , Diyashev I. R. , Brovchuk A. V. , Alpatov A. A.
Published: December 2007

Recent years have seen a growing trend towards applying new and advanced technology in the Russian oil and gas business to maximize productivity and enhance assets value. This has led to improved efficiency and greater technical challenges. In large measure, Sibneft owes its predominant position as one of the rapidly growing oil producers in the Russian energy business to its willingness to embrace new technology in order to enhance the value and maximize the productivity of its assets. This paradigm shift has been critical to the company, not only to maintain its leadership among the majors in Russia, but also to be consistent with the country's aggressive strategy to enhance production rapidly to meet local and international energy demand.

This paper focuses on how Sibneft management has been keeping abreast of new technology in order to meet these technical challenges. Romanovskoe oilfield, which is located in the Western Siberian region, is one such field that has been subjected to this proactive philosophy. Due to the heterogeneous characteristics of the reservoir, inefficient thin beds and relative low permeability, specific applications or "right sizing" of technology are crucial to ensure effective exploitation of the field potential. All the wells in the field are either producing via horizontal wells or have been fracture-stimulated since the beginning of their production history.

The critical success factors that emerged from the applications are accurate well placement within the thin oil column (landing the well in the right place and at the right angle), avoiding poor quality reservoir and undulating wellbore for the horizontal wells, and fracture-stimulating the wells in the low productivity regions. The adoption of the strategy has seen substantial increase in the field total production, which is otherwise difficult to achieve without appropriate applications of specific technology. The successes on overall enhance the long-term value of the asset.
Implementation of Remote Start-up Facility on Offshore Installation
Authors: Ismail Saiful Adli , Shukur Maisarah
Published: December 2007

Remote start-up facility is initiated and implemented at some of Petronas Carigali Sdn Bhd (PCSB) offshore installation as one of the initiative to reduce production deferment and optimize resources.

Conventionally, operation's personnel are required to visit the remote platform to perform the local/manual start-up activity whenever the platform has shutdown due to process or other abnormality. The process upset may be originated from the platform itself or due to cascading effect from receiving platform after it has shutdown.

During bad weather, the traveling time by boat to the remote platform is difficult and normally takes longer traveling time. There are also cases where the start-up activity needs to wait on weather when the traveling by boat is not possible due to rough sea.

The delay due to traveling time and further delay during bad weather cause the delay in restarting-up the platform. This start-up delay results in production deferment.

The implementation of the remote start-up facility will enable the operation's personnel to remotely start-up the drilling platform. It is then no longer required to travel to the platform for local/manual start-up activity.

Based on the study conducted, the restart-up delay due to traveling time contributes significantly to the production deferment. Therefore, if the start-up activity can be done from remote i.e. from mother platform or FPSO, then the production deferment can be reduced significantly.

By having remote start-up facility, the total downtime and thus production deferment could be minimized not only during bad weather condition but also during normal weather condition as the travel to the platform is no longer required. This production deferment would accumulate from year to year if not being addressed.

This facility has been implemented on MASA platforms where existing control and safety shutdown systems were modified together with additional instrumentations installed. Only minor modification at relatively marginal cost was required but yet capable of generating relatively significant reduction in deferment.

At MASA platforms, the remote start-up facility is initiated from the FPSO by opening the respective surface safety valves (SSV), Shutdown Valves (SDV) and Choke Valves (CV).
Resistivity Data From A Seismic Survey? An Alternative Approach To Assist Inter-well Water Saturation Mapping
Authors: Widarsono Bambang , Saptono Fakhriyadi
Published: December 2007

Information about spatial distribution of rock true resistivity (Rt) throughout an oil or gas field is always desired. Since seismic survey is the only widespread source that provides information for inter-well locations, considerable efforts have been devoted to extract as much data as possible from it. It is therefore desirable to be able to extract Rt from seismic attributes normally represented by acoustic impedance (AI). This paper presents a field trial of an approach that is basically an application of artificial intelligence (artificial neural network, ANN) on well-log and seismic data based on a proven theoretical relationship that relates Rt to AI. The approach itself, which has been successfully verified through a series of laboratory trials, includes training of the ANN using relevant well-log data, Rt prediction using the trained ANN, and blind tests as means of result validation. An oil field located in East Java is chosen for the trial. It has been shown that there is a certain correlation between log-derived resistivity and log-derived AI. As the approach is applied to map the resistivity and water-saturation, comparisons between conventional/ deterministic water-saturation (Sw) map and the corresponding map resulted from the trial has shown the superiority of the method in presenting inter-well variations in water-saturation. It is also found that the new method has provided a high level of flexibility in interpreting and distributing the inter-well Sw values.
The Use of Integrated Simulation in Decision-making for the Development of Qiaokou Oil-rim Gas Condensate Field
Authors: Guo Xiao , Du Zhimin , Jiang Yiwei , Sun Lei , Bi Jianxia , Liu Xueli
Published: December 2007

The development of complex, deep gas condensate fields with oil ring was once a difficult and uneconomical task to perform. The optimization of conceptual design has now become cost efficient through the use of integrated simulation. This presentation focuses on the integrated study of Qiaokou oil- rim gas condensate field , located in Zhongyuan oil field. The reservoir is of low permeability, low porosity, deep pay and has three fault-isolated produced zones, named Qiao14, Qiao69 and Qiao58 blocks. In 2002, 28 infills were drilled on the basis of adding incremental reservoirs. With the advent of widely available high-accuracy reservoir predicting technology, under-balanced drilling technology and large- scale fracturing technology in Zhongyuan oil field, encouraging factors and results led to a desire to further field- scale development plans. An detailed integrated study of Qiaokou oil-rim gas condensate reservoirs was proposed.

This study involved building a highly detailed earth model to accurately define the geologic framework, and a scaled-up simulation model to optimize the field demonstration project. Based on well log, geologic, and core data, individual-layer data and the faulted structure were mapped. Reservoir behavior of oil-rim gas condensate reservoir is modeled using a 3-D reservoir simulator. The model incorporates a description of the phase behavior of gas and oil rim, well stimulation and compaction in the reservoirs.

The multi-disciplinary demonstration of reservoir evaluation, gas engineering, PVT analysis, numerical simulation, gas production practice, fracture acidizing on Qiaokou oil-rim gas condensate reservoirs has been accomplished by earth scientists, field engineers, and reservoir engineers. An integrated simulation incorporating the demonstrated results of these engineers has been presented to make decisions in Qiaokou oil-rim gas condensate field development.

The study showed the integrated numerical modeling of Qiaokou oil-rim gas condensate reservoirs can be cost effective and SINOPEC has already ratified the further development plan in light of the results of this study. Our conclusions and recommendations will help improve future management and development of Qiaokou oil-rim gas condensate field.
The Investigation of Potential Residual Oil Tapping Technique in the Late Stage of High Water Cut Period in Daqing Oilfield
Authors: Liu He , Yan Jianwen , Hongxue Han , Gang Cao
Published: December 2007

This paper introduces the performance history of the Daqing Oilfield and analyzes the potential for further development.

The residual oil distribution characteristics are analyzed taking the advantage of the core data of Well La8-JP182 and Well Bei1-330-J49. Then the numerical simulation method is used to analyze the recovery ratio, production rate, and the variation of pressure gradient under different production conditions. Finally, the technology of potential tapping of the isolated untabulated reservoirs, tabulated reservoirs, the huge thick reservoirs, and multiple rhythm reservoirs are brought forward in this paper.
Granular Gel-Polymer Treatment Successful in Daqing Oilfield
Authors: Liu He , Han Hongxue , Li Zhuling , Wang Bo
Published: December 2007

Reservoir heterogeneity, along with the oil to water viscosity ratio, cause fingering and water breakthrough along fractures or higher permeability layers of in water flooding oilfield. This in turn decreases the water sweeping volume and water drive effect, making the medium or lower permeability layers poorly productive or even unproductive. As a result, the production wells will be flooded before due or will have a rapidly increased water-cut. Blocking higher permeable layers with chemical reagents along the flow direction of water can efficiently increase the water-affected volume; adjust productive and absorptive sections of the reservoir. Therefore, the water-cut can be decreased, the oil production can be increased, and the objective of stable oil production and lower water-cut can be achieved. This paper presents the techniques used in a field test project conducted at Daqing Oilfield. Granular gel-polymer was used as blocking agent. Economically improved oil production and reduced water-cut were observed.
Numerical Models Help Analyze Lost-Circulation/Flow Events and Frac Gradient Increase to Control an HPHT Well in the East Mediterranean Sea
Authors: Sanad Medhat , Butler Carl , Waheed Arshad , Engelman Bob , Sweatman Ron
Published: December 2007

This paper presents the analysis methods and modeling results from a post-well study of a lost-circulation/flow event in a challenging high-pressure/high-temperature (HPHT) exploration well. The effects of well conditions such as wellbore pressure changes, rock mechanical properties, and geo-pressures are reported. Results from a new lost-circulation, finite element analysis (FEA) model also help explain why various formation-sealing treatment systems (some conventional and others new) failed to reduce the losses into the loss zones. After a new fracture gradient (FG) enhancement squeeze system (FGESS) was implemented, it effectively halted the losses. Full circulation was then re-established to stabilize the well. The well had been losing at an equivalent circulating density (ECD) of 16.4 lbm/gal. Application of the FGESS treatment increased the wellbore pressure containment integrity to sustain an equivalent of 17.0 lbm/gal mud as measured by a formation integrity test (FIT). This remarkable improvement in the apparent or near-wellbore FG (NWFG) or fracture re-initiation pressure (FRIP) was achieved along with several other cost-saving factors.

A new FEA model is also discussed to help show how the FRIP or NWFG was increased by the FGESS treatment and may predict how FGESS treatments can increase the FRIP or NWFG in future wells. This fully 3-D model uses various types of treatment data and well conditions such as wireline log data for formation stresses and rock properties to calculate a FGESS treatment's higher FRIP or NWFG. Upon re-entry of the well 7 months after the successful FGESS treatment, the seal in the loss zones was still holding against HPHT conditions. This sustained seal reduced costs even more and allowed a liner to be set successfully without drilling fluid or cement losses in the reservoir section of the well. The conclusions of the study can help optimize well plans for future wells in the area, which can lead to lower costs for drilling fluids, casing design, cementing, and completion equipment.
Quantitative Risk Assessment for DP Operations Aboard the Belford Dolphin
Authors: Naismith S. , Cowan M. , Linzi P.
Published: December 2007

This paper presents a summary of a study that has been carried out to demonstrate that the drilling operations planned for the dynamically positioned drillship, the Belford Dolphin, can be carried out within defined quantitiative risk acceptance critieria for oil spills. The basis for the study is the vessel's past position keeping history, the operating experience for similar vessels, the subsea equipment design and the uncertainties associated with the subsurface geology of the project.
Eastern Gulf of Mexico: Inhibitive Water-Based Drilling Fluid Sets Ultra-Deepwater Records
Authors: Watson Pat , Meize Bob , Aldea Catalin , Blackwell Billy
Published: December 2007

Two record wells were recently drilled in the ultra-deepwater Eastern Gulf of Mexico. The wells were the fastest two wells drilled in water depths greater than 7,000 ft in the GoM. A high-performance water-based mud (WBM) was used to drill the intermediate sections. The fluid had comparable performance to a synthetic-based mud (SBM), with the advantage of cuttings disposal permission in this environmentally sensitive offshore area. Significant savings were realized by not carrying the cuttings to shore for disposal. Other advantages included (a) no losses while running and cementing casing and (b) easier displacements. The fluid was re-used on two consecutive wells and then stored for further applications.

The authors will detail the careful planning that coupled with fit-for-purpose solutions allowed setting these records while reducing the overall well cost. The wells were drilled in the Lloyd Ridge area of the Eastern Gulf of Mexico, categorized as "zero-discharge" for SBM cuttings. The use of the high-performance WBM saved the hauling and disposing of approximately 2,000 bbl of cuttings on each well. Cost savings were also accomplished by avoiding fluid losses when running and cementing the casing. On a similar project drilled completely with SBM, 2,156 bbl of mud were lost while running and cementing the 13⅝-in. casing.

Comparison of drilling and economic performance of the new water-based mud and the synthetic-based mud are included in this paper to offer a comprehensive analysis. Also presented are innovative solutions introduced to optimize hole cleaning and shale inhibition.
Onshore Mobile Platform: A Modular Platform for Drilling and Production Operations in Remote and Environmentally Sensitive Areas
Authors: Kadaster Ali G. , Millheim Keith K.
Published: December 2007

Anadarko Petroleum Corporation has demonstrated the use of a reusable Modular Platform* to minimize the footprint and environmental impact of a drilling operation in an ecologically sensitive area.

The modular platform was installed on a location in the North Slope Borough of Alaska, for the continuous coring of the Hot Ice #1, a joint venture hydrate exploration well in cooperation with the U.S. Department of Energy (DOE) and Noble Drilling subsidiary, Maurer Technology Inc.

The concept was approved in spring of 2002 and the design, fabrication, systems testing, and mobilization to North Slope was completed by the start of field operations in January 2003. The removal of the platform is scheduled for March 2004. During all phases of the project, the platform was monitored for stability and its impact on the tundra.

The modular platform application represents a significant step towards establishing temporary or permanent drilling and production sites in ecologically sensitive areas with a minimal footprint and environmental impact. It is readily configured for deep or shallow wells, for applications in the arctic or the marsh or the foothills. The modular platform is also suitable to be designed and utilized as a production platform or pipeline facility, in areas without road access.
Basis of Design for Coiled Tubing Underbalanced Through-Tubing Drilling in the Sajaa Field
Authors: Suryanarayana P. V. , Smith Bruce , Hasan ABM , Leslie Charlie , Buchanan Richard , Pruitt Randy
Published: December 2007

This paper describes the technical basis for the design and implementation of a Coiled Tubing underbalanced drilling (UBD) campaign in the Sajaa field in Sharjah, UAE. The campaign calls for up to three multi-laterals per well to be drilled underbalanced from existing wells thru-tubing. The paper describes the analysis, modeling, result and their implication in the selection of the operational approach. The key issues associated with the campaign, many of which were unique and challenging within the context of UBD, and their consideration in the basis of design and implementation plan are discussed, with specific reference to the Sajaa-3 well, which was the first candidate. These include

■ Temperature modeling and thermal considerations due to the high bottom hole temperature, ■ Compositional PVT behavior of the produced fluid, ■ Feasibility, underbalanced operability and controllability of CT drilling thru tubing, ■ Risk to underbalance from near-wellbore depletion of the reservoir due to long-term production from the motherbore, ■ Estimation and impact of the productivity of the motherbore and open laterals while drilling subsequent laterals, ■ Risk from reservoir parameter uncertainties, ■ Hole cleaning risks, ■ Designing for zero flare, ■ Consideration of mechanical and hydraulic limitations to the drillable lengths, and ■ Equipment limitations.

The paper details the analysis approach used, assumptions, models used, and results. It should be noted that the Sajaa produced fluid is a retrograde condensate, and the inflow performance was non-linear, and therefore consideration of these in the basis of design becomes critical.

The goal of this work was not only to create the technical basis of design for the well Sajaa-3, but also to set the parametric limitations for a wide range of well types that were likely to be encountered in the continuation of the campaign. Based on this work, an approach to drilling and monitoring the well so as to minimize the risks was developed and formed the basis of the drilling operation. The campaign is now on its seventh well, and the results of the drilling operation of Sajaa-3 and the subsequent wells, and their implications to the design basis are also discussed.
Advanced Analysis Identifies Greater Efficiency for Testing BOPs in Deep Water
Authors: Franklin C. Mark , Vargo Richard F. , Sathuvalli U. B. , Payne Mike
Published: December 2007

Pressure testing Blowout Preventers (BOPs) with Synthetic-Based Mud (SBM) requires lengthy testing times as a result of pressure/volume/temperature (PVT) influences associated with SBM. PVT influences are especially pronounced in deepwater and high-pressure test environments.

This project was motivated by an effort to better understand the mechanics that transpire during BOP testing. The primary objective was to demonstrate that the pressure decline is quantified by the fluid PVT behavior, mechanical influences, and thermodynamics of pressurization and subsequent cool down. The second objective was to demonstrate that the pressure decline caused by a leak can be detected reliably and efficiently with high resolution pressure data.

It was theorized that the phenomena primarily result from heat added to the system during pressurization. To pursue this investigation, real-time PVT data was gathered at the cementing unit (CU) suction and discharge while testing the BOP. In addition, pressure-temperature (P-T) gauges were placed in the drillstring: one at the drill floor, one at the midpoint between the drill floor and the BOP, and one above the BOP stack. The gauges confirmed significant heat up as the system was pressured up for each test. The pressure decreased as the system cooled back towards the ambient. Modeling techniques were developed to understand the system response. This paper presents salient aspects of data acquisition, data interpretation, and modeling techniques.

Results demonstrate the potential to significantly impact the industry with respect to safety, time, and costs for BOP testing.
Qualitative Risk Analysis of Emergency BOP Control Systems to Ensure Availability
Authors: Sattler Jeff , Lewis Ed
Published: December 2007

Many of the latest generation of ultra deepwater capable rigs included emergency BOP (Blow Out Preventer) control capabilities, sometimes referred to as secondary intervention systems. Such systems represent the last line of defense in containing a well. Should it be necessary and unavailable, the result could be environmentally and humanly catastrophic.

Building on installations that have been in service for many years, these capabilities range in functionality and purpose, from providing an alternate means to operate BOP functions in the event of total loss of the primary control system to assisting personnel during incidents of imminent equipment failure or well control problems. They can be actuated automatically or manually, and utilize components of the primary BOP control system or be totally independent. With as many permutations as there were rigs built, an understanding of the capabilities and limitations that exist on a particular rig is of critical importance in assessing the risks associated with a drilling program.

While there currently are no standard terms in use to describe the essential attributes of systems, this paper recommends definitions and terms for a common understanding. The defined terminology is then utilized to compare and contrast system parameters, identifying various system strengths and weaknesses for use in risk analyses.

Possible enhancements to existing emergency control systems will then be discussed, as well as their benefits and anticipated costs. Finally, the paper will recommend best practices for moored rig operations and those for operations utilizing DP (Dynamic Positioning).