bluuebunny/crossref_metadata_2025 huggingface dataset:
Leadership and Culture: Turning Theory Into Reality
Authors: Siokos G. P.
Published: December 2007

The oil and gas industry operates across the globe in many and varied national cultures. Moreover, the industry also involves many different organisations working together to achieve success; each with its own distinct organisational culture. It is therefore understandable that people in this industry, working with such diverse cultures, face unique challenges to improve its performance across a range of performance indicators, including safety, health and environment. This becomes a focus for leaders, at all levels within the industry and individual organisations.

Significant improvements in safety performance have been achieved in recent times. However, a work environment in which "nobody gets hurt" requires the development of an effective and sustainable culture that values safety. Leadership, at a strategic, individual level and team level, must focus on the related behaviours that demonstrate personal accountability and responsibility for safety.

In the past, attempts to improve safety were seen as short term ‘fads’; something to do because ‘we have to’, often resulting in them being treated as a distraction from the ‘real’ work priority issues. This was commonly a reflection of a culture that believed that safety and productivity were not compatible.

Incident free workplaces are created where the culture reflects a belief that good safety behaviour contributes to productivity and therefore safety improvement strategies are an integral and valued part of all business processes.

Effective (safety) leadership impacts all work functions.

The hypothesis presented in this paper is that leadership, specifically HSE Leadership, is critical to create the work environment necessary for people to develop the commitment, confidence and competence to practice safety as intended by their organisations and that to be fully effective it must be applied on a ‘whole of organisation approach’.

This presentation will provide some insights into ‘good practice’ of leaders working successfully to develop effective safety cultures in the international oil and gas industry across all functional areas.
Competence for Managing HSE in Deep Offshore Operations - Relevance Requisite for Indigenous Contractors
Authors: Olaoye Dele
Published: December 2007

Deep offshore operations are sine qua non to the future of the Nigerian Oil & Gas industry. The focus of exploration and field development activities by the operator companies is shifting from land/ swamp to offshore and even deep offshore. However, the challenges that this trend poses to local content is yet to be fully comprehended.

One of the major issues that would affect the relevance of contractor companies in the emerging scheme is competence and compliance gaps in managing Health, Safety & Environment (HSE).

This paper x-rays HSE challenges that are peculiar to contractor operations deep offshore. The analysis takes into consideration some of the major exploration & production support services as case studies. The objectivity that may be behind the unwillingness on the part of deep offshore activities to throw open especially HSE sensitive activities was also discussed.

By bringing to the fore the risk elements of these HSE Challenges; competencies required in terms of systems, knowledge, and ethical application that needs to be acquired by Nigerian companies keen in participating in the future were detailed.

However, as a way forward, pathway to acquisition of these competencies and ingraining it into the business management systems of contractor companies was traced.
A Robust Approach to Flow Unit Zonation
Authors: Lawal Kazeem A. , Onyekonwu Mike O.
Published: December 2007

Flow units are usually defined in assigning petrophysical characteristics to different zones of a detailed description of a reservoir. Because of differences of concepts, the available techniques usually show discrepancy. In this study, a flow unit is defined as a differential volume of the reservoir rock within which the flow characterizing parameter is statistically uniform but differs significantly from those of adjacent volumes. On this basis, a semi-empirical model, which honours both geology and petrophysics of the rock and applicable to both sandstone and carbonate formations, has been formulated. This is the basis of the Generalized technique subsequently developed.

Using the case of a sandstone formation, with performance objectives of consistency, accuracy of permeability-porosity relationship and minimization of number of flow units, five existing techniques were compared with the new approach. The results show that the Generalized technique is superior. This improved reservoir characterization may be attributed to the flow characterizing parameter proposed, the use of which has been extended to correlation of zones between adjacent wells. It is also discovered that flow zonation is independent of depth ordering, as volumes far apart are shown to have similar hydraulics and should be treated as such. Based on this concept, a nomograph for simple hydraulic analysis of porous media is also presented. Finally, the needs for further validation of the technique in other geologic regions and development of user-friendly package based on these principles are highlighted.
Application of Generalized Pressure Perturbation Principle to Cubic Equation of State Formulation
Authors: Isehunwa Sunday O. , Falade Gabriel K.
Published: December 2007

Cubic equations of state are commonly used for predicting the properties of reservoir fluids. They are simple to use and require few parameters during computations. They have also been found to produce results that are comparable to the more rigorous multi-parameter equations. However, they are still regarded by many as mere comprehensive correlations of fluid properties because of a number of weaknesses and limitations. This work addresses two weaknesses of cubic equations of state commonly highlighted in literature, viz: that they do not seem to have deep theoretical foundations and are not as accurate as non-cubic equations. A pressure perturbation technique based on a simple adaptation of the Weirtheim's first order thermodynamic perturbation theory has been developed and used to formulate a cubic equation of state. The practical equation formulated was applied to pure fluids and samples of Niger Delta Petroleum fluids. The results show more accurate predictions than the commonly used SRK and PR equations. This work suggests that cubic equations could have deeper theoretical roots than otherwise thought and provides a theoretical framework for improving the accuracy of cubic equations of state.
IFC Performance Standards
Authors: Miller P.
Published: December 2007

The International Finance Corporation (IFC) Safeguard Policies have been the basis for IFC's leadership and approach to environmental and social sustainability. Based largely on the World Bank's operational policies, IFC adopted its current set of Safeguard Policies in 1998 in order to manage environmental and social issues in the private sector business environment in emerging markets. IFC embarked on an ambitious two-year process in FY04 to update all of the Safeguard Policies through a single initiative to develop the next generation of a policy framework based on a clear, concise and comprehensive policy on social and environmental sustainability. Following an intensive review and analysis of the strengths, weaknesses, and gaps in coverage of the current Safeguard Policies, IFC has recast the Safeguards as a Policy and Performance Standards on Social and Environmental Sustainability.

The Performance Standards are often considered the defacto standards even in the absence of IFC participation in the project. They could potentially apply to all projects in developing countries.

The Performance Standards contain clear and concise requirements geared toward project outcomes and promote performance improvement through monitoring, reporting and feedback. They place new emphasis on implementation through management systems, deal with social and environmental issues in a more integrated manner, and strengthen policy coverage of issues such as pollution, climate change, and biodiversity. In addition, the Performance Standards address a number of additional subjects of direct concern to the private sector such as labor and working conditions and community health and safety.

IFC's social and environmental standards are the building blocks for our approach to sustainability and are embodied in IFC's Safeguard policies, Environmental Health and Safety Guidelines, and Disclosure Policy. Together these provide a framework to help our clients manage project risks and improve their performance, and help IFC improve development outcomes and maximize the development impact of our investments.
FPSO Gas-Detection System Performance Enhancement and Monitoring
Authors: Benmebarek S. , Hanlon S.
Published: December 2007

Operating FPSO's in severe weather conditions probably constitutes one of the most challenging aspects facing today's Offshore Oil Industry. Part of the challenge resides in achieving an optimal availability and reliability of the Gas Detection Systems.

The proposed paper describes the approach and methodology adopted in response to specific challenges encountered while commissioning the Gas Detection System onboard an FPSO operating offshore the East Coast of Canada.

Its contents will hopefully fit the Conference theme of "Delivering Sustainable HSE Performance Improvement Through Sharing".

The subject Gas Detection System was being commissioned in preparation for first hydrocarbons in the thick of winter, and prevailing weather conditions exacerbated the situation, resulting in a significant number of gas detectors' faults being recorded.

An action plan was put in place to identify the underlying causes and come up with the necessary improvements and enhancements to raise the system's performance to an acceptable level.

Three major initiatives were undertaken to achieve the set objectives prior to production operations starting, and to maintain them through the life cycle of the facility.

These initiatives were:

A comprehensive internal operability review to determine the overall reliability for detecting gas within a given fire zone, and confirm all hardware and software is operational and within design parameters. An external review study by a specialist consultant to assess the detectors performance against the performance target using 3D modelling and mapping techniques. he development of an in house tracking mechanism to monitor both real time and retrospectively the performance of all gas detection devices on the FPSO.

In conclusion, the above highlighted initiatives successfully allowed the FPSO Operator to demonstrate, and continue demonstrating an acceptable level of reliability and availability of the gas detection system, at all times during production operations.
Water Production Management Strategy in North Uthmaniyah Area, Saudi Arabia
Authors: Al-Mutairi S. M. , Al-Harbi M. H.
Published: December 2007

A water management strategy was initiated in the North Uthmaniyah area of Ghawar field in late 1999. The strategy main objectives are to reduce operating expenses associated with water handling and avoid capital investment required for the expansion of water handling facilities while engendering a more efficient recovery process. The strategy was implemented through four initiatives: operating of high water cut wells on a cyclic basis, conducting rigless water shut-off jobs, drilling horizontal sidetracks of existing vertical completions and drilling wells with partial penetration completions. All of these practices were designed to leverage Ghawar Arab-D advantages of high reservoir conformance and displacement efficiency, which will ultimately yield high oil production with minimal water production.

The techniques of operating of high water cut wells on a cyclic basis and rigless water shut-off jobs have been successful in slowing down water production at low cost. Based on the recent encouraging results, it appears economically and technologically feasible to produce the remaining oil at lower water production rates, by drilling horizontal sidetracks during the middle and later production periods in mature fields concurrent with a rigorous surveillance and monitoring program. Finally, wells with partial penetration completions have been introduced to the area recently to delay water production and accelerate oil production.
Why do Watertight Doors Still Kill People? Long-Term Measures to Control the Risk
Authors: Tronstad L.
Published: December 2007

Automatically power-operated watertight doors harm people every year. A review of some recent accidents shows weaknesses in design, marking, maintenance, operation and training for operation of this hazardous machinery (doors). The paper focus on the man-machine safety issues, and presents recommendations for long term measures to control the personal risk involved with operation of such doors.
Behavior Change and Enforcement: A Practical Approach
Authors: Almeida A. , Mannering M. , Lombardo G.
Published: December 2007

Schlumberger health, safety, and environment (HSE) programs have evolved over the past 20 years, accompanied by a steady decline in accident rates. However, in 2003 and 2004, improvement in accident rates had reached a plateau, and analysis indicated that more than 50% of accidents involved a failure to follow established, documented procedures. The need for a program to address behavior enforcement and behavior change was evident, and in 2004, the company formed a task force of employees and consultants to define such a program. This paper describes that program and its development, including definitions of its three components: accountability, hazard analysis and risk control, and observation and intervention. Also discussed are the must-have elements, changes in new-employee training, initial reaction to the program, and results to date.
Synergy between Integrity and HSE
Authors: Alawai S. M. , Azad A. K. , Al-Marri F. M.
Published: December 2007

Though Abu Dhabi Marine Operating Company (ADMA-OPCO) has been producing hydrocarbons for over 40 years without any major accident, the aging facilities; environmental restrictions and social obligations demand more than usual safety practices. The Shareholders, therefore, introduced some proactive measures in E&P Companies, in addition to traditional HSE activities, to ensure facilities' integrity. The development of ‘Integrity Assurance Key Performance Indicators (KPIs)’ by ADMA-OPCO in late 2003 was envisaged by ADNOC to measure and ensure the effectiveness of the integrity assurance activities.

The paper demonstratess how the Integrity Assurance KPIs' instigate to systematically identify potential process safety / integrity incidents; assess their possible causes and be able to demonstrate that appropriate policies, prevention measures, safety systems procedures and emergency response systems are established. The paper establishes a synergy between HSE and Integrity.
Health Management System
Authors: Madera A. , Sandri S.
Published: December 2007

The growing emphasis on the responsibility and accountability of company management for the safe guarding of health of employees as well as for the community is reflected in recognition that good health standards benefit industry and its employees. All the major Oil and Gas Companies have issued policy statement on HSE conservation. To assist Eni E&P Division Subsidiaries Companies to address health matters in a systematic manner, Eni E&P Division has accepted the use of the HSE Integrated Management System (HSE IMS) as the basis for the implementation of health into its operational activities. This paper describes the "Health Management System" (HMS) developed as a risk assessment based integrated element of the HSE IMS and how health can be managed in a way similar to other aspects of the business.
Automatic Shaker Control
Authors: Scott E. L.
Published: December 2007

Traditionally, shale shakers have been manually operated machines. Key constituents such as basket angle and acceleration are featured as either fixed or manually adjustable components, which tend to yield limitations with a shaker's screen life, flow capacity, and operator safety. This work proposes an automatic shaker control to adjust the basket angle, manage acceleration, and decrease operator intervention.

In order to achieve automatic shaker control, a manualstyle shale shaker design was modified with electronic sensors, an actuator, an on-board computer, and software to automatically control the fluid level on the screens. The computerized shaker system measures the fluid level on the screens, detects input flow, and measures the basket angle. The shaker then adjusts the basket angle and acceleration boost in order to control the fluid level on the screens. The shaker maintains the fluid level near a constant optimum value, which is set by the user.

In low flow conditions, this proper fluid pool coverage of the screens promotes screen lubrication and reduces friction, which increases screen life. In high flow conditions, the fluid level control helps prevent whole mud loss. The automated shaker does not merely rely on basket angle control to manage high flow conditions. The automated shaker's arsenal against mud loss also includes an automatic boost and anticipation of new flows. The automatic boost feature temporarily increases the shaker acceleration (g-force) applied to the basket in order to process higher flow rates. Finally, when the input flow to the shaker stops, the basket is automatically tilted to the fully uphill position to prepare for the next flow. This decreases the possibility of sudden rushes of fluid from flooding the shaker before it can automatically adjust to a more uphill position. These shaker modifications maintain screen lubrication, increase screen life, and assist in the prevention of whole mud loss, all while reducing operator HSE exposure.

Tests have shown that the automated shaker increases screen life, decreases operator intervention, and helps prevent whole mud loss. Automatic shaker control can operate a shaker near optimum. The benefits of this can lead to increased shaker performance and decreased expenses.
Successful Field Use of Advanced Dynamic Models
Authors: Bjørkevoll K. S. , Rommetveit R. , Rønneberg A. , Larsen B.
Published: December 2007

This paper focuses on how advanced dynamic models can be best used in critical drilling and completion operations. To date, R&D in this area has focused mainly on developing reliable and accurate models for drilling and completion operations, and has not focused on how these models are used in practice. Examples from recent managed pressure operations in North Sea wells are presented. These examples give insight into how such models can best be utilized in the future.

In these examples dynamic models were used to calculate target surface pressure to keep open hole pressure within narrow margins between fracture and pore pressures. Models were utilized under several displacement operations, including liner cementing, to determine how to regulate choke pressure to compensate for changes in density and rheology. Important factors leading to a successful operation were 1) update of input parameters, 2) model calibration prior to critical operations, and 3) good communication with the drilling crew.

Based on the experience from these operations, the paper discusses in detail how to move to the development of future software tools that make advanced dynamic models more accessible for all kinds of operations. Some key points of this vision are: Models are directly linked to real time dataModels are integrated with intelligent algorithms that automatically interpret deviations between measured data and model predictionsModels and diagnosis algorithms are integrated with data acquisition systems and run real time driven by real time data.Models do not require the presence of model experts.

This aims at a software system that is useful also for personnel with little knowledge and experience in advanced modeling during drilling operations. This will provide more reliable monitoring of all drilling and completion operations, reliable warning when operations become critical, and help lead the crew through critical phases of the well. This will lead to a reduction in non-productive time through better decision making and improved focus on critical operations.
The Effect of Elongational Flow Through the Drill Bit on the Rheology of Polymeric Drilling Fluids
Authors: Lozano J. , Miska S. , Takach N. , Yu M. , Saasen A.
Published: December 2007

Polymers have been used in drilling fluids for different purposes. They serve as emulsifiers and lubricants, reduce filtration, stabilize clays, flocculate drilled solids, increase carrying capacity and reduce drag among other functions1. Because of the wide use of polymers in the petroleum industry it is extremely important to investigate the actual performance of the fluid downstream of the drill bit nozzle and the effect of elongational flow on the molecular chains of the polymer.

This paper presents the results of experiments performed in an indoor flow loop at the facilities of Tulsa University Drilling Research Projects (TUDRP). The data obtained from the experiments was analyzed and compared at upstream and downstream conditions. Samples of the fluid before and after experiments were taken for rheological analysis and for comparison. Also, the samples were used to measure and analyze the change in molecular weight.

A model that compares the strain rates developed at the nozzle and the critical strain of the fluid is presented.

The results of this study yield valuable information on the effect of elongational flow through the drill bit nozzle on the rheology of polymeric fluids.
Investigating Solids-Carrying Capacity for an Optimized Hydraulics Program in Aerated Polymer-Based-Fluid Drilling
Authors: Lourenço A. M. F. , Martins A. L. , Andrade P. H. , Nakagawa E. Y.
Published: December 2007

This paper concludes the analysis of the results from two sets of experimental tests performed at PETROBRAS real scale test facility aiming the evaluation of solids return times in aerated fluid drilling. It reviews important results on effects such as liquid and gas injection rates and particle diameter from air-water experiments1 and extend the discussion by adding the effect of the viscosity of liquid phase and annular back pressure on the transport capacity of solids in a vertical well with an aerated polymer-based drilling fluid. Results indicate that the gas has a major effect in accelerating the liquid phase, which would be responsible for carrying the particles to the surface. The trend was confirmed in the experiments with polymer-based mud, where lesser return times were associated with the fluids with higher liquid-phase viscosity. The concept of actual liquid velocity coupled with a procedure for particle sedimentation velocity calculation in non-Newtonian fluids adequately reproduced the experimental results.
Managed Pressure Drilling (MPD): Planning a Solution for San Joaquin Field, Venezuela
Authors: Soto R. , Malavé J. , Medina M. , Díaz C.
Published: December 2007

Located in Eastern Venezuela, San Joaquin Field, with a daily production of about 800 mmcfgd, is the most important gas field in Venezuela.

Vertical wells have been drilled through two shale/sandstone-layered formations where the gas payzones are located. The extent of the drilling problems is reflected in the 2003 average fluid losses, which were more than 2000 barrels per well. If it is added the non-tangibles as the uncertainty of consequences in mud weight changes, we have the perfect setting for new thoughts on well planning, being Managed Pressure Drilling the logic next step, with the vision towards reducing problems, time and cost.

The two most important formations are Merecure, with 1500 ft of thickness and 25 layers (pressure ranges between 4000 psi and 700 psi) with shale intercalations that add an attention point for the field complexity. San Juan Formation has its own considerations, with upper layers depleted and fractured, and a pressure differential of 2000 psi with lower layers that have high economical interest in the near future.

The first challenge was to generate a geomechanic model, which used "breakout control" theories, for the development of the mud weight window to assure hole stability during drilling operations.

Well control optimisation for high productivity layers where under balance conditions applied was a fundamental consideration due to environmental regulations, surface equipment design and ECD control.

Well planning included "effective ROP increase" criterions, high durability drill bits, aggressive performance for favourable drilling conditions and parameters control in a target oriented philosophy. All of these relevant issues were the synergistic points for engineering and operations integration.

Actually, five wells have been drilled without lost circulation reports, notable increase in ROP and a reduction in total drill bits used. These have been important results and a very good start for the learning curve in this technology implementation.

The MPD experience in San Joaquín Field is one of the first formally recorded in Venezuela and with these results it can be said that this technology will be in this country for a long time.
Underbalanced Drilling Borehole Stability Evaluation and Implementation in Depleted Reservoirs, San Joaquin Field, Eastern Venezuela
Authors: Azeemuddin M. , Maya D. , Guzman E. A. , Ong S. H.
Published: December 2007

Drilling underbalanced is often expected to prevent formation damage, avoid lost circulation, and increase rate of penetration. However, it is also risky and may lead to borehole collapse due to lack of positive support provided by the borehole mud. Hence, its feasibility should be evaluated thoroughly through an accurate evaluation of in-situ stresses and a realistic estimation of formation rock mechanical properties. These two entities combined with the proposed borehole trajectory and mud weight design play an important role in avoiding borehole instability problems and achieving the field objectives.

A study was conducted in San Joaquin field in Eastern Venezuela, to evaluate the feasibility of drilling underbalanced in highly depleted sands inter-layered with normally pressured shales. Data required for the study was obtained from five wells in the field (pressures, daily drilling reports, wireline logs, leak off tests and rock mechanical tests).

A geo-stress model was developed, including pore pressure model, minimum and maximum horizontal stresses, and overburden stress. The in-situ horizontal stress directions were estimated from caliper logs, image logs and other field data. Formation rock mechanical properties were obtained using a program which utilizes the log data from the field and estimates the more representative static mechanical properties, which were then calibrated with the lab results. The combined geo-stress and mechanical properties models were calibrated with respect to drilling induced fractures and breakouts observed on the image logs. The calibrated models were used to estimate the required mud weights for drilling under various degrees of underbalance. Instabilities (breakouts) associated with each degree of underbalance were also quantified. The required mud weights to avoid shear and tensile failures, or the expected breakouts for a given mud weight, can be estimated from the generated contour plots for any borehole azimuth and inclination in the field.

The results of the study were successfully implemented in the field, resulting in cost benefits of $1MM over five wells. Lost circulation was significantly avoided, and improvements in drilling rate as well as savings in rig days were achieved.

The outcome of the study is expected to provide guidelines for underbalanced drilling for future wells in the area.
Improved Production in Low-Pressure Gas Wells by Installing Wellsite Compressors
Authors: Behl N. , Kiser K. E. , Ryan J.
Published: December 2007

Production from low-pressure gas wells was improved by widespread/extensive installation of well site compression in the Waddell Ranch Project. The Project was implemented in three phases over a period of three years beginning in June 2000. A total of 63 wells have been tested with well site compression; there are now 52 permanently installed compressors. The candidates were selected by testing the wells in the low-pressure area and additional wells highlighted by the Moving Domain study. Compressors were installed on successful test candidates in phases one and two. Phase three involved expanding the project to test the remaining 39 gas wells in the area by leasing compressors. This was done to reduce capital cost, take advantage of higher gas prices at the time, and gather data for proper design and sizing of the compressors.

Following studies were carried out as part of the project:

Compare the response of wells in high-pressure area and low-pressure areas of the reservoir to wellhead compression. Feasibility study investigated the field wide compression by use of Central Compression System. This was followed by a study to determine the economics of well site compression versus central compression system. Financial study was carried out to determine the economics of leasing versus purchasing the well site compressors.

The results and conclusion of project were:

Reservoir technologies like Moving Domain study helped in candidate selection. The compressor project has been a success with an average initial uplift of 102 MCFD per well for 52 successful Judkins wells tested. Although the gas production increased significantly the decline rate has also increased indicating that we have accelerated gas production with some addition in reserves. Central Compression system with an estimated project cost of $12 million was found uneconomical. Individual well site compression was more economical method for gas production optimization. A total of $850,000 have been spent in three phases over 3 years.

Several operational improvements evolved which decreased downtime and cost of maintenance and enhanced the profitability of these installations. All these have been listed under the lessons learned part of the paper.
Use of Uncertainty Analysis to Improve Production History Matching and the Decision-Making Process
Authors: Costa A. P. A. , Schiozer D. J. , Poletto C. A.
Published: December 2007

In the present E&P scenario, decisions have to be taken considering risks. An important part of risk evaluation can be accomplished through the evaluation of the impact of uncertainties in the performance of the petroleum fields, yielding higher possibility of success, quantification of possible losses, minimization of sub-optimal development and identification of opportunities.

The objective of this work is to use the quantification of the impact of geological uncertainties to improve the production history matching in a Brazilian onshore field located at Potiguar Basin with 17 years of production history. The main advantage of this process is to provide alternatives for possible adjusted models related to the global rate of liquids, oil and water, allowing the selection of the best model to the be latter refined and adjusted on a well to well basis.

The key point of the applied methodology in the project is the use of the concept of geological representative models (GRM) which are selected based on the integration of objective functions previously defined to the context. These GRM models are selected to represent all combined models which compose the distribution curve (risk curve) of the process. The distribution curve is obtained through the concept of derivative tree technique which combines the possible scenarios using the numerical simulation to predict reservoir behavior. The numerical simulation is used to increase the reliability of the results allowing one more detailed analysis for each model. An automated tool and parallel computing are used to speed up the process.

The utilization of the automated tool as well as a defined methodology to quantify the impact of uncertainties improved the viability of the history matching procedure with a significant reduction of time and effort in the repetitive tasks, improving its results and yielding a more reliable production forecast.
The Impact of Interfacial Tension and Pore-Size Distribution/Capillary Pressure Character on CO2 Relative Permeability at Reservoir Conditions in CO2-Brine Systems
Authors: Bennion B. , Bachu S.
Published: December 2007

Injection of CO2 has been used for enhanced oil recovery (EOR) in many light and medium gravity reservoirs. Consequently, sequestration of CO2 in oil reservoirs in conjunction with CO2-EOR is a method that is under consideration for reducing CO2 emissions into the atmosphere. Many oil reservoirs are underlain by an aquifer, and EOR processes often involve water-alternating-gas (WAG) processes. Proper understanding of the relative permeability character of such systems is essential in ascertaining CO2 injectivity and migration, and in assessing the suitability and safety of prospective CO2 injection and sequestration sites. While many measurements exist for CO2-oil systems, very few data, if any, exist for CO2-brine systems.

This paper provides an analysis of brine-CO2 interfacial tension (IFT) measurements that were conducted for equilibrium brines and CO2 at reservoir conditions, and the detailed 700 MPa mercury-injection capillary pressure tests conducted on all rock samples to determine specific pore size distributions. Three sandstone and three carbonate potential sequestration zones in the Wabamun Lake area in Alberta, Canada, were evaluated, together with a caprock shale. This data set has specific application to the study of the behavior of injected CO2 in contact with bottom water or water-saturated zones that may be encountered in CO2-EOR projects, as well as for CO2 sequestration in deep saline aquifers. The analysis shows some correlation between the CO2-brine IFT, pore size distribution of the intergranular porous media and CO2-brine relative permeability. However, due to the high degree of variability in the pore system character of the different sandstone and carbonate facies tested, additional, better-controlled comparative tests are required to validate these trends. The hope is that, ultimately, compilation of more extensive datasets will allow appropriate selection of proper CO2-brine relative permeability relationships at reservoir conditions for intergranular sandstone and carbonate formations on the basis of relatively simple measurements of pore system geometry and IFT. These data will also provide a valuable tool for the estimation of CO2-brine relative permeability for the simulation and evaluation of intergranular sandstone and carbonate formations on a worldwide basis.
Transforming Data into Decisions to Optimize the Recovery of the Saih Rawl Field in Oman
Authors: Dozier G. C. , Giacon P.
Published: December 2007

This paper will illustrate the collaborative approach taken by an integrated team (operator and service company) charged to demonstrate, within a one-year time period, measurable improvement in well productivity in the Saih Rawl field of Oman. Although the field has been producing for more than five years, the results shown are based on a one-year application of a systematic approach to field optimization. This process is the dynamic integration of historical data and new information, technologies, and engineering diagnostics to systematically identify, layer-by-layer, key parameters affecting productivity and to optimize performance based on "present-state" analyses. In doing so, the program has produced some of the highest productivity wells in the field's history.

Oman has developed into a fast-paced fracturing arena, with challenges similar to those encountered in the tight gas fields of south Texas in the United States. Well productivity is highly dependent on hydraulic fracturing effectiveness and operating practices. Understanding the resultant hydraulic fracture effectiveness is increasingly complicated by the changing mechanical and reservoir properties related to depletion and intralayer communication (crossflow).

Gas is produced in the Saih Rawl field from two distinct main reservoirs: the Barik and Miqrat formations. The Barik formation, at depths from 4500 to 4900 m, is composed of stacked sandstone packages with varying shale content separated by relatively thin heteroliths (sandstone/shale mixtures) of 3 to 7 m thickness. These heteroliths are believed to provide pressure barriers to the various flow units observed in the Barik formation. The Barik formation produces gas of varying richness from most of its units, with a high condensate content produced from layers that are producing currently below dewpoint. On the other hand, the Miqrat formation, found at depths >5100 m, produces lean or dry gas. The combination of relatively low and heterogeneous permeability along with complex hydraulic fracture height growth makes it necessary to perform ad hoc, multistage hydraulic fracturing treatments and to produce these wells commingled to be commercially economic. A systematic approach, incorporating historical pressure trends by unit and theoretical assumptions, validated by indirect field evidence, to onsite decision-making has resulted in the placement of more effective fracture treatments in an operationally efficient manner. The results of these efforts yielded the highest producing well in the field's history in an area of known depletion; the highest-rate Miqrat production well, an overall improvement of zone productivity, and a better understanding of the factors impacting productivity, layer-by-layer, in the Barik and Miqrat formations.
A New IOR Technology To Homogenize Horizontal Well Injectivity/Productivity Profile
Authors: Fernandes P. D. , da Silva M. G. F. , Bedrikovetsky P.
Published: December 2007

Non-uniform distribution of flow rate along horizontal wells results in early water/gas coning, early breakthrough of water/gas during flooding, etc. For injector wells, injection flow rate profile along the horizontal length leads to low sweep efficiency and to large oil-filled by-passed zones.

In the current work, a variable distribution of flow open area along a horizontal well, with or without sand control, is proposed, to correct the flow rate profile along it. An uniform flow profile is achieved by means of unevenly spaced slots or perforations along the liner or sand control device.

An analytical model was developed for flow inside and around the horizontal well with unevenly spaced slots or perforations along the liner or along the sand control device. The model couples flows in well and in the reservoir in well vicinity. The analytical model provides an explicit formula for slot/hole density along liners or screens in injection/production horizontal wells.

Applications of the model to design horizontal well in cases of injection and production, with or without sand control, with inflow control device are discussed.

The technology has been successfully applied in some oilfields onshore and offshore Brazil, where horizontal producer wells were equipped with specially perforated and slotted liners. The purpose is to homogenize flow along horizontal producer or injector wells, in order to delay gas and water coning and improve the sweep. The varying slot/perforation density is calculated by the analytical model, and the calculated option was implemented in some wells.
Best Practice for Fields Producing Below the Bubblepoint
Authors: Thompson M. A.
Published: December 2007

In regulating production on the United Kingdom Continental Shelf (UKCS) the UK Department of Trade and Industry (DTI) has permitted operators, on a case by case basis, to produce below the bubble point locally to the producer well in order to accelerate production or, where pressure support is not economically viable, to produce below the bubble point more extensively.

The maturity of the UKCS means that smaller fields are now being developed and operators are also looking to reduce operating costs in mature fields that are approaching cessation of production (COP). The issue of production below the bubble point is therefore becoming more important.

This paper investigates how operators have been producing below the bubble point over the last decade with the objective of updating guidelines for producing below the bubble point. The success of monitoring techniques is examined and field and well behaviour is compared with common rules of thumb and prediction methods.

Data was collected for 12 fields that had produced below the bubble point in the last 8 years and 5 fields were selected for more detailed analysis. The fields selected represent a cross-section of typical UKCS fields with both vertical and horizontal wells and local and deep production below the bubble point. The analysis techniques include ‘Gas Production Envelope’ calculations, and the use of diagnostic plots of GOR, pressure and cumulative oil recovery.

Of all the fields operating locally below the bubble point, reservoir damage was indicated in only two fields both of which had flowed with bottom hole pressures of about 50% of the bubble point pressure compared with a more normal minimum flowing bottom hole pressure of around 75% of the bubble point pressure.
An Approach for Snaky Well Productivity Under Steady-State Condition
Authors: Qi Zhilin , Du Zhimin , Liang Baosheng , Tang Yong , Wang Shouping , Deng Ruijian
Published: December 2007

As a type of complex well, snaky well is pretty promising especially in the geometrically complicated reservoirs and has been reported recently. Accurate prediction of well productivity is vital. However, conventional productivity calculation methods for horizontal wells could not be applied directly for snaky wells because the production part in the well bore has large fluctuation in the vertical direction and therefore the wellbore pressure drop should not be neglected.

On the basis of the distribution of velocity potential produced in an infinite reservoir by one snaky well, this paper uses the mirror image and the principle of superposition and obtains the velocity potential and pressure distributions for bottom water drive reservoirs with and without gas cap, and edge water drive reservoir. Along the well bore, we then study the flow characteristics and establish a pressure drop model. Coupling wellbore flow with fluid flow in the formation, we develop and further solve a productivity model for the snaky well.

The high precision and practicability are clearly demonstrated using an example. Such well productivity approach reduces uncertainty and better satisfies the real condition, resulting in more accurate prediction.
The Study and Field Applications of Hydraulic Fracturing Technology in Clay-Carbonate Reservoirs with High Temperature, Deep Well Depth, and Densely Distributed Natural Fractures
Authors: Jiang Tingxue , Zhang Yiming , Wang Yongli , Ding Yunhong , Luo Ning , Xu Zejun , Feng Xingkai , Zhang Hongmei
Published: December 2007

A hydraulic fracturing technology is put forward in clay- carbonate reservoirs whose characteristics (take well A as an example) are: 1)deep well depth(4237.5m), high temperature(146 °C), high pore pressure (42MPa); 2)high content of clay(15-22%) and high content of velocity-sensitive minerals (54-71%) such as illite and kaolinite; 3)horizontal stratifications are richly distributed as well as some natural fractures or cavities with high angles; 4) the matrix has a ultra-low permeability (0.0087-0.022 × 10-3μm2) and ultra-low oil saturation(12.3-18.3%). Consequently, the highlights of the hydraulic fracturing technology are: 1) a new fracturing fluid is developed using a super grade Guar as its densifier, with the viscosity of the base fluid being 93 to 102 mPa.s, while the residue content of 197 mg/l. 2) two types of high strength ceramic proppant are used, one is 20/40 mesh, the other is 40/60 mesh; 3) a new kind of mini-fracturing technique is utilized to determine the well head pressure under various pumping rate, near well bore friction pressure, loss coefficient and decrease reservoir temperature and control fracture height as well; 4) a new optimization technique of fracturing treatment parameters is developed systematically,. such as systematic laboratory tests for the fine evaluation of formation, strategy to avoid multiple fractures, monitoring technique of bottom hole pressure, etc.; 5) a new strategy is adopted to help flowing back of fracturing fluid, which takes the stress sensitivity near the well bore and natural fractures’ influences in to account. What's more, the technology has been put in to filed application in the well A, the fracturing treatment is success and the post-fracturing performance is satisfied. Summarily, a systematic fracturing technology is put forward adapted to clay-carbonate reservoirs, and it has a great significance in the near future especially in China.
Tyrihans Field Development Overview
Authors: Munkvold F. R. , Knoff T.
Published: December 2007

Tyrihans is an oil and gas-condensate field offshore Mid- Norway. Oil reserves are 29 million Sm3 and gas reserves are 35 billion Sm3. The field will be developed as a subsea project with 5 templates having 9 producers and 3 injectors. Production start-up is July 2009.

The field development is innovative in the following aspects:

Cost effective development with a 43 km tie-back to the Kristin platform through an 18" pipeline. Tie- back is possible because the pipeline will have direct electrical heating to prevent formation of hydrates and to preserve temperature. Pressure support with both gas injection and raw sea water injection. This is feasible by installing two water injection pumps subsea and using available power and compressor capacity at neighbouring fields. Extensive use of advanced wells. The oil producers are dual-lateral with approx. 1.5 km horizontal reservoir sections, equipped with down-hole ICVs (Inflow Control Valves) and gas lift. Both main bore and laterals will have 8.5" hole diameter, made possible by using 8" expandable liners.

Important reservoir management and simulation issues are:

Tyrihans consists of two structures, which cannot be produced independently. Handling gas and water coning in a two-front system and keeping track of fluid contacts are challenging. The northern structure consists of an 18 m thin oil zone with a gas cap. To simulate recovery from thin oil zones is challenging. The simulation model has horizontal grid, in order to have the required vertical resolution of the oil zone. Correct modelling of pipeline flow and flow assurance. The long, single pipeline tie-back makes well testing difficult. Reservoir monitoring and management must then be based on subsea flow meters and gauges. Production optimization will be performed from an onshore support centre.

With the chosen reservoir development strategy high recovery is obtainable. The simulated oil recovery in the southern part is 52%, and the gas recovery in the northern part is 80%.