bluuebunny/crossref_metadata_2025 huggingface dataset:
Formulating a Safety Management System for a Global Drilling Organization
Authors: Jenkins R. W. , Garcia H. A.
Published: December 2007

Texaco formed a Global Drilling organization in January of 1999. At that time Texaco did not have a Safety Management System in place specifically dedicated for drilling operations. This paper will outline the steps taken to formulate a safety management system for a Global Drilling organization and identify critical success factors.

Immediately following the reorganization to a worldwide functional group, Global Drilling personnel examined safety in its geographically based drilling organizations and established a dedicated safety management system.

Benchmarking was utilized to determine the actual safety performance of Global Drilling operations. Following this exercise, appropriate goals were established and communicated to all drilling personnel. Guidelines for safety data collection were also established in order to capture and maintain accurate safety records. A process map was created to outline the possible outcomes of all safety incidents.

A plan was then implemented to promote the following:

■ Leadership Visibility ■ Individual Accountability ■ Contractor Initiatives ■ Highly Visible Actions

This paper will expound on the above action plan. Conclusions will illustrate the significant performance improvement achieved by the establishment and execution of this plan. As an example, in the two years of operation, Global Drilling's lost-time accidents have decreased by 87%.
Offshore Drilling Experience with Dual Derrick Operations
Authors: Munch-Søegaard Lars , Nergaard Arnfinnn
Published: December 2007

Smedvig took delivery of the fully class 3 dynamic positioned new generation drilling units West Navion and West Venture in February 2000. Both are equipped with full capacity dual Ramrigs with the capability of running two strings in the water simultaneously. In a single well application the advantage lies in using the dual system for parallel making and breaking bottomhole assemblies, tool strings and pipestands and in running casing/BOP in parallel with drilling top hole. In a multiwell subsea template situation there is an additional potential in performing simultaneous in-water operations. While the main rig is in a BOP/riser drilling mode, the auxiliary rig can drill tophole and install surface casings in the next well. With proper planning, this could imply subsequent moving the BOP to the next well without having to come back to surface. In later phases the Xmas tree or other modules may be installed in other slots/positions in parallel with the main activity. The paper describes enhancement of drilling operations through a selection of cases that are experienced and proves that utilisation of the dual activity feature leads to a paradigm shift in drilling and completion operations.
Using Conventional and Unique Methods to Drill a Technically Demanding Shallow Flow Zone
Authors: Roller P. R. , Magner M. D. , Drury R.
Published: December 2007

Deepwater drilling operations require a great deal of planning and logistical support, even under the most ideal situations. When shallow water flow hazards are a concern, the importance of the planning and logistical support increases tremendously.

The Green Canyon 288 "Intruder" Project utilized both conventional and unique methods to control the shallow water flow zones that are prevalent in the Green Canyon area of the Gulf of Mexico. These included the use of sophisticated hydraulics software to maintain the equivalent circulating density (ECD) required to inhibit the flow and prevent losses while drilling to casing point.

The operational and logistical considerations and preplanning that combined for the successful drilling of a prospect on Green Canyon Block 288 with an upgraded semi-submersible drilling rig will be examined in detail.
Water Flood Monitoring in an Oman Carbonate Reservoir Using a Downhole Permanent Electrode Array
Authors: van Kleef R. , Hakvoort R. , Bhushan V. , Al-Khodhori S. , Boom W. , de Bruin C. , Babour K. , Chouzenoux C. , Delhomme J. P. , Manin Y. , Pohl D. , Rioufol E. , Charara M. , Harb R.
Published: December 2007

In 1998, Schlumberger and Shell jointly launched a project to prove the concept and economic viability of Dynamic Reservoir Drainage Imaging. The goal was to provide a timelapse monitoring of water saturation, allowing an evaluation of drainage efficiency in oil and gas reservoirs. To achieve this objective, the resistivity approach was used: in this technique, an array of electrodes is cemented at reservoir level, providing a continuous reading of the formation resistivity. Applications of this technology include real-time monitoring of water cone development and water table rise, provided there is a sufficiently large resistivity contrast between hydrocarbon and water zones.

A field test program was set up in 1999, with Petroleum Development Oman, to demonstrate the technology and to evaluate data to be acquired in Oman. The well that was selected for the electrode array deployment is located in the Fahud field. By the end of August 1999, an observation well was drilled in the Natih-E carbonate reservoir, at the center of a water-flooding cell formed by dual horizontal producers and injectors. Two 16-electrode resistivity arrays were deployed behind the casing, across the zone of interest, to measure the variation in formation conductivity related to water injection in the nearby injector wells. The measurement period was anticipated to last approximately 18 months before the monitoring cell would be flooded.

After the array deployment was successfully performed, the initial acquisition period indicated that the array reading was affected by nearby casing effects. This resulted from current leaks to the casing that reduced the depth of investigation of the system considerably. Nevertheless, the data recorded versus time through successive acquisitions made in late 1999 and early 2000 has clearly shown variations of the array response across the reservoir. Those variations have been interpreted as water saturation increase at particular depths, stressing the fact that the oil had been unevenly swept, and that early water breakthrough was to occur earlier than expected at the producers. This interpretation was backed-up by production data and saturation logging, which indicated respectively water cut and localized saturation increases.
Reduction Of Well Emission During Clean Up And Testing Operations By Rig
Authors: Hassan M. M. , Fadaq A. S. , Beadie G.
Published: December 2007

Most of the wells offshore and onshore require acid stimulation to remove formation damage and improve production. The chemical fluid used in stimulation jobs and the low pH of the returned fluid during the back-flow of the acidised wells have an adverse effect on the production lines and downstream facilities.

ZADCO, in co-ordination with ADMA-OPCO have used successfully the Oil Re-Injection System as the most cost effective, feasible and safe option to reduce the well emissions to the natural environment during clean up operations. This system utilises a single-phase pump to boost the separator pressure and overcome the sea line pressure.

This paper presents the two phases ZADCO have carried out for reduction of well emissions during the clean up operations, in which it highlights the main components of the Oil Re-Injection System and its impact on the rig such as the space constraints, power requirements and safety risk assessments. Also, it highlights the achievements accomplished by ZADCO and ADMA-OPCO and the future plans to achieve zero flaring.
Considerations for the Design, Development, and Testing of an Integrated Large Monobore Completion System to Facilitate High-Rate Production
Authors: Simonds Randy , Swan Tom
Published: December 2007

Monobore completion techniques have been noted for their capability to provide operators with a high degree of maintenance flexibility. This enhanced flexibility is made possible by the fact that there are no restrictions on any tool that may be deployed in the liner as often happens when completions have tapered production strings. While this can result in substantial economic benefit, the advantages often are not realized until later in the life of the well.

Although maintenance is always an important consideration, the general volatility of oil prices has forced the industry to target operational strategies that can offer quicker returns on investment. Therefore, innovations to the traditional monobore concepts have been needed. The completion system discussed in this paper employs large-diameter production tubing, and therefore, it can provide not only the maintenance benefits of a monobore system but also the added advantages of an increased flow area. The increased flow area 1) allows the number of wells to produce a given reservoir to be reduced and 2) enables production rates to be increased, which in turn, reduces long-term operating expense since the reservoir can be depleted in a shorter period of time.

The specific benefits of the large-bore monobore completion are as follows: No restrictions are imposed on productionProduction rates are maximizedGas turbulence areas are eliminatedNo restrictions on any service/intervention toolsTubing retrieval to the liner top is allowedFull access to the liner for squeezing or mechanical isolation of the perforations is allowedAncillary equipment requirements are minimized.
Scale Control Strategy and Economical Consequences of Scale at Veslefrikk
Authors: Tjomsland T. , Grotle M. N. , Vikane O.
Published: December 2007

The Veslefrikk field is located in block 30/3 of the Norwegian sector of the North Sea. The field has now been on production for approximately ten years, and can be described as being in the decline phase. The Brent and IDS zones contain different fluid systems, and are produced through several commingled wells. Seawater is injected for pressure support. The first water breakthrough occurred in 1992. Although the ion composition of the Veslefrikk formation waters are not extreme when compared to other North Sea formation waters, severe scale formation has been observed. Both CaCO3 and BaSO4 scale have been identified. This is probably due to high reservoir temperature, 125°C (CaCO3), and the commingled production (BaSO4). Based on the field experience a preventive scale control strategy has been implemented. Scale inhibitor squeezes, re-perforation and mechanical and chemical scale removal are applied to maintain the productivity in the wells. Recently the effect of scale formation upon the production rates and cash flow, has been assessed. Two different scenarios, ‘No scale control’, and ‘No scale’, have been studied. These cases have been compared to the baseline production profile. This consists of the historical production data and the base case prognosis for the field, which includes scale control at today's level. The work, covering the period from start of production to June 1999, shows that 9 million Sm3 less oil would have been produced if no scale control had been implemented. This represents a value of approximately 1100 million USD. The cost of the scale control operations which have been performed, including inhibitor squeezes, reperforations and mechanical and chemical well stimulations, are approximately 6.3 million USD. 3.7 million Sm3 more oil, representing a value of 400 million USD, could have been produced if the field had not experienced any scale formation. Assuming constant reserves, the accelerated production represent a 320 million USD increase in the total field lifetime NPV. In addition, the operating costs would have been reduced. The results clearly show that scale control operations are highly beneficial, and it is recommend to intensify the preventive scale control at Veslefrikk.
Occurance, Prediction and Prevention of Zinc Sulfide Scale Within Gulf Coast and North Sea High Temperature/High Salinity Production Wells
Authors: Collins I R , Jordan M M
Published: December 2007

Precipitation of mineral scales causes many problems in oil and gas production operations: formation damage, production losses, increased workovers in both producers and injectors, poor injection water quality, and equipment failures due to under-deposit corrosion. The most common mineral scales are sulfate and carbonate-based minerals. However, scale problems are not limited to these minerals and there have recently been reports of unusual scale types such as zinc and lead sulfide. This paper focuses on zinc sulfide scale that has been has been found in several fields along the Gulf Coast of the USA and fields within the North Sea Basin. Scale deposition has caused significant pressure and rates reductions in high temperature, high rate gas, condensate and black oil wells. After acid washes to remove zinc sulfide scale (and other acid soluble solids), production rates and flowing tubing pressures returned to previous levels, but new scale deposits formed in many wells and re-treatments were required. Topside process equipment most noticeable low-pressure separators and hydrocyclone were observed to suffer reductions in performance owing to zinc sulfide scale deposition. In addition, there are significant risks associated with acid treatments in high temperature, high-pressure gas wells: corrosivity of the acid at high temperatures (general corrosion, sulfide stress cracking, and chloride stress cracking) and safety (hydrogen sulfide generation by acid dissolution of zinc sulfide plus high pressure pumping). One possible method for preventing production declines and reducing the need for high temperature, high-pressure acid jobs, is to use scale inhibitors or a chelating agents to prevent the formation of zinc sulfide scale. The relative effectiveness of eight scale inhibitor chemistries and two chelating agents in preventing formation of zinc sulfide scale has been determined. The required scale inhibitor concentrations are significantly higher than concentrations needed for common sulfate and carbonate scales. For chelating agents, it is possible to prevent the formation of zinc sulfide scale with the required concentrations being proportional to the Zn2+ ion concentration in the scaling brine. This paper outlines the testing methods utilized for chemical screening and for prediction so that assessment of the potential problem within fields during appraisal can be assessed prior to production commencing and a method of managing the risk made available.
Current Directions in Screening-Level Ecological Risk Assessments
Authors: Carlsen T. M. , Efroymson R. A.
Published: December 2007

Ecological risk assessment (ERA) is a tool used by many regulatory agencies to evaluate the impact to ecological receptors from changes in environmental conditions. Widespread use of ERAs began with the United States Environmental Protection Agency's Superfund program to assess the ecological impact from hazardous chemicals released to the environment. Many state hazardous chemical regulatory agencies have adopted the use of ERAs, and several state regulatory agencies are evaluating the use of ERAs to assess ecological impacts from releases of petroleum and gas-related products. Typical ERAs are toxicologically-based, use conservative assumptions with respect to ecological receptor exposure duration and frequency, often require complex modeling of transport and exposure and are very labor intensive. In an effort to streamline the ERA process, efforts are currently underway to develop default soil screening levels, to identify ecological screening criteria for excluding sites from formal risk assessment, and to create risk-based corrective action worksheets. This should help reduce the time spent on ERAs, at least for some sites. Work is also underway to incorporate bioavailability and spatial considerations into ERAs. By evaluating the spatial nature of contaminant releases with respect to the spatial context of the ecosystem under consideration, more realistic ERAs with respect to the actual impact to ecological receptors at the population, community or ecosystem scale should be possible. In addition, by considering the spatial context, it should be possible to develop mitigation and monitoring efforts to more appropriately address such sites within the context of an ecological framework.
The Influence of Corrosion Inhibitor / Scale Inhibitor Interference on the Selection of Chemical Treatments Under Harsh (HP/HT/HS) Reservoir Conditions
Authors: Graham G. M. , Frigo D. M. , McCracken I. R. , Graham G. C. , Davidson W. J. , Kapusta S. , Shone P.
Published: December 2007

The challenges of scale and corrosion control in a number of new HT/HP fields in the North Sea, such as the Heron cluster wells in the ETAP (Eastern Trough Area Project) development, are substantially more severe than those normally encountered. The extreme reservoir conditions (T > 175 °C, P ~13,500 psi, TDS > 350,000 mg/L), depths (~ 5 km) and the need for long tiebacks (26 km) along the sea bed, give rise to very large temperature and pressure changes throughout the production system. The high temperature and extreme water chemistries lead to faster scale nucleation and growth kinetics, and to a very severe corrosion potential, which is further exacerbated by the high flow velocities (> 25 m/s) and high shear stress (>500 Pa) experienced in the flow lines. Engineering foresight during the project development stages of this reservoir have successfully reduced the potential scale and corrosion challenges, for example by: •use of de-sulphated wash-water (DSSW) to reduce sulphate scaling potential;▪use of high chrome steel production tubulars to reduce corrosion potential

Such "Engineering Solutions" have reduced the risk of the scale and corrosion problems to a level that is both manageable and economic using chemical treatments, albeit at relatively high levels of scale and corrosion inhibitors.

This paper describes the results and conclusions from an extensive series of performance experiments under the very severe conditions pertaining to the Heron cluster system.

Due to the number and complexity of production chemicals to be selected in this study, a "hierarchy" was established for the various species based on their relative impact to field development/operability. Although the effective application of a Threshold Hydrate Inhibitor was ultimately considered to be the highest priority for the economic development of the field, this paper concentrates on the demonstrated interferences between a pre-selected list of candidate corrosion inhibitors (priority #2) and scale inhibitors (priority #3).

Indeed, final product selection was based upon the combination of inhibitors that would not interfere with one another, rather than on the absolute performance of the individual products.
Developing Coiled-Tubing Techniques on the Karachaganak Field, Kazakhstan
Authors: Jones RD
Published: December 2007

Coiled Tubing was introduced to the Karachaganak Field in 1997 as part of a package of technical enhancements designed to improve field productivity. Initially planned only for acid stimulation work during the summer, the service has been extended into an all year round support to the Workover, Stimulation and Well Service programs. Examples of the type of operations performed are described. These include tubing cutting, cleaning and acid washing as required to remove tailpipes during workovers. Fishing to clean up old wells prior to the workover. Inflatable packer isolations for acid stimulation and wellhead repairs.

Introducing a new service, such as coiled tubing, to any location, presents an interesting challenge. Developing and applying the techniques within the service, particularly on an established, corrosive, gas/condensate production field with old, high rate, well stock, located in a remote area with extreme weather conditions, challenges the technical application of Engineers, operators and support services.
Methods and Results of Inspecting Coiled Tubing and Line Pipe
Authors: Stanley Roderic K.
Published: December 2007

Nondestructive Inspection of coiled tubing (CT) and coiled line pipe (CLP) is not only essential in assuring product quality, but also can be useful in determining physical attributes. In this paper are discussed some non-invasive methods that have been found to be useful in assessing these products.
Opportunities to Improve the Success Rate of Coiled-Tubing Operations
Authors: Engel S. P. , Mackey P.
Published: December 2007

Coiled tubing has been an invaluable tool to the oil and gas industry for some forty years. Each time that coiled tubing is rigged up and run into a well it carries with it a risk that the objective of that run will not be met. This paper analyses that risk based on some two years continuous records in the Asia Pacific Region and finds that the average rate of a successful run is 82% over a 23-month period. A database of about 1200 runs demonstrates the type, cause and frequency distribution of failures. Risk management options are reviewed and potential solutions offered.

The cause of failures is most frequently attributed to unknown well conditions. However, inadequate job planning, operator errors and equipment failures also have a significant contribution. The levels of technical complexity demands are escalating. In balance, there are increasing operational skill levels, equipment reliability improvements and a better focus on pre-job planning. This, then, tends to hold the status quo at a constant frequency over time. In order to increase the rate of success, lowering the difficulty of the jobs attempted and/or increasing the operating and equipment reliability will be required. Simplicity and reliability tend to go hand in hand. However, there is a general industry temptation to over-engineer and overcomplicate both the work scope and the equipment. The result may be viewed as unreliable and perhaps, not cost effective coiled tubing solutions.

The opportunity exists to significantly reduce the run failure count. This could be achieved by lowering ambitions and allowing equipment and skill levels to ‘catch up’ with established industry coiled tubing solutions. It then raises the question "Is it better to do something simple well or to risk failure with technical ambition?" This paper concludes that the current failure rate can be improved upon with various corrective actions. This is essential in order to progress to further technical advancements.
Improvements in Coiled-Tubing Window-Milling Operations Cut Costs and Increase Reliability, Prudhoe Bay, Alaska
Authors: L. Jeffrey , Johnson Bryan , Wilson Steve , Luckey Kenneth J. , Collins William
Published: December 2007

The original through-tubing window milling procedure was designed to run through 4-1/2" tubing, milling a window in the 7" casing below the tubing tail. The window was milled off a pre-set mechanical whipstock that was set on electric line before the coiled tubing unit was moved over the well. It generally took 2 to 3 mill runs before an effective exit window was obtained in the 7" casing.

The goal of the project was to obtain an effective one-trip window exit. The milling assembly had to reduce the torque and work effectively with minimal weight on bit to allow deployment on 1-3/4", 2" and 2-3/8" coiled tubing. By milling the window in one trip versus 2 trips, approximately 12 hrs of rig time could be saved.
Coiled-Tubing Cement Squeeze in Colombia's Casanare Field
Authors: Tarazona F. , Stephens R. , Crow W.
Published: December 2007

This paper discusses recent coiled tubing (CT) cement squeeze planning and operations conducted in the Casanare Field in Colombia. Zonal isolation for gas shutoff was identified as a critical factor to help reduce the GOR for wells that would otherwise shut in due to gas handling limits of the production facility. The planning phase included a cement laboratory audit that was used to identify the reason for discrepancies of the cement design between the laboratory conditions and the full scale mixing trial. Voltage variation during laboratory tests was identified as a major factor which affected the mixing energy. Another source of discrepancy between the laboratory results and the sample batches with field equipment was the amount of energy imparted to the system by use of centrifugal pumps. Cement design properties were critical to achieve sufficient thickening time and filter cake quality in the presence of relatively high reservoir temperature and reduced formation pressure. Discretionary disposal of several batches of cement was required until those design parameters were met. Communication and crew training were fundamental to identifying and resolving problems, especially in an area that had not yet conducted this type of operation.
Automating Candidate Selection for Coiled-Tubing Drilling
Authors: Brown M. , Nas S. , Lusted I.
Published: December 2007

As fields are becoming more mature and improved reservoir interpretation is identifying so-called "By-passed" hydrocarbons, more sidetracks will be required. Selecting a well to reach a certain target in the reservoir can be a long task as a number of issues have to be considered. Using an auditable process for selecting the optimum sidetrack method and the best wellpath to reach a certain target can take a drilling engineer several months on a multi well development. In order to optimise this process all of the relevant parameters have to be considered. An automated system using a database now allows quick identification of the correct sidetrack method and selects the most suitable wellpath for the sidetrack. This fully transparant method starts with the reservoir target and then works through all the issues associated with the well selection process.

This paper describes the Candidate Selection Methodology, examples of the criteria utilised to evaluate the suitability of the Drilling Technique and examples of the speed of Selection for a candidate Well and the output of the process.
A Comprehensive Model and Computer Simulation for Underbalanced Drilling in Oil and Gas Wells
Authors: Fan Jun , Gao Changliang , Taihe Shi , Liu Huixing , Yu Zhongshen
Published: December 2007

This paper presents an advanced dynamic model and computer simulator for underbalanced drilling. The model is formulated based on the theory of multiphase transient flow referring to the drilling mud, water, oil, gas and solid particles. All the important factors affecting underbalanced drilling have been taken into account comprehensively in the model, including IPR relation, physical properties and mass transfer behavior of fluids, flow regime and phase migration features, geometry and deviation of wellbore as well as the different operating modes which may be carried out in practical underbalanced drilling.

A specific numerical approach is adopted for solution of the theoretical models and on the basis, an advanced computer simulator is developed for undertaking simulation, study and planning of underbalanced drilling operations. The computer simulator differs from existing simulators because it is fully dynamical and interactive with users. Researchers and users can change different operating modes according to their will at any time during simulating process just as they are really performing an underbalanced drilling operation. The simulator can track all the complicated and complex conditions in underbalanced drilling process, and all the related parameters and profiles of parameter distribution along wellbore at any time can be shown dynamically.

Through a number of simulating computations, tests and verifications, it is shown that the model and simulator are valid and in accordance with actual drilling practice under different and complicated conditions. It is of great importance for consummating underbalanced drilling theory and on the spot application. A typical simulation result and case study are also presented in the paper.
Experimental Study on Carrying Capacity of Cuttings in Annulus for Air/Mist Drilling
Authors: Liu Huixing , Fan Jun , Yan Renjun , Yu Zhongsheng
Published: December 2007

Nowadays the use of air and gas as a circulating medium for drilling oil and gas wells is becoming an attractive practice because of its great advantage over conventional mud drilling. However, the occurrence of some troubles due to poor carrying capacity of cuttings in air/mist drilling is not uncommon. Meanwhile, the determination of air/gas injection rate desired to undertake air and gas drilling is also closely related to the actual moving regularity of cuttings in annulus. It is obvious that researches on migration rate and carrying capacity of cuttings within borehole are essential to air/mist drilling. Although there are some theoretical models for prediction of cutting migration velocity and therefore the carrying capacity of cuttings, experimental studies are also essentially important because of the complexity of actual liquid, gas and solid multiphase flow in wellbore and the uncertainty of theoretical models. In this paper, some experimental studies were performed to investigate the moving regularity and carrying capacity of cuttings in wellbore. Some comparisons between the testing results and theoretical models are also presented in the paper. It is seen that such a study is valid and effective in prediction of the migration velocity and analysis of the motion regularity of cuttings in borehole. Therefore, the required practical air injection rate to keep the necessary carrying capacity in air/mist drilling can be determined definitely.
Integrating Technological and Financial Uncertainty for Offshore Oil Exploration: An Application of Multiobjective Decision Analysis
Authors: Suslick Saul B. , Furtado Ricardo , Nepomuceno Francisco
Published: December 2007

Oil companies are presently facing a competitive scene due to high pricevolatility and increasing complex decisions. In this scenario, firms shouldhave adequate decision tools to evaluate cost and benefit impacts from thefinancial, environmental, technological, and market factors. This paperdescribes a methodology where a decision-maker explicitly considers twoobjectives when evaluating new petroleum opportunities in an offshore area-financial and technological gain. The Multi-Attribute Theory (MAUT) is usedsimultaneously to consider the technological challenges of the capitalbudgeting process in an exploration and production firm. Prospects from fivedifferent basins in an offshore area comprising distinct risk and objectiveswere selected for the proposed study. The methodology presented in this workdemonstrates that in some mature areas the advantages to exploration arerestricted further only to financial gain, based upon the present economicpotential of the basin. On the other hand, other seemingly less attractiveareas, such as deep horizons in deep-water basins, may represent potentialtargets for new exploration as a result of the interaction of financial gainand technology advancement. The proposed model can provide significant insightinto petroleum exploration and guide managers to better investment decisions aswell as provide information to decision makers regarding the efficiency oftechnological gain at the firm level.
A Methodology to Collect and Assess Data for Characterization of a Company's Hydrocarbon Resource Base
Authors: Bolling John D. , McKee Michael L. , Reiter Doris F. , Freeman Stephen C.
Published: December 2007

This paper describes a systematic, consistent methodology to collect reserve and economic information for characterizing a company's oil and gas resources. The authors firmly believe value is realized, both internally and externally, by being able to effectively characterize a company's hydrocarbon resources. The methodology is comprised of four elements: resource definitions, tying resources to production forecasts, valuing resources, and assessing uncertainty. A data collection process is outlined so that the same data can be used for multiple purposes including long range planning, portfolio management, regulatory reporting, reserve management, technology planning, and establishing performance targets. Finally, implementation issues associated with developing a company hydrocarbon resource characterization are reviewed. The paper is a summary of processes developed by ARCO from 1998 to 2000 to better characterize company resources and manage its portfolio of assets.
Sustainable Growth Journey
Authors: Abbott Robert E. , Unruh Gary L.
Published: December 2007

Conoco believes that sustainable development is a comprehensive way of approaching business to ensure that financial excellence is achieved in concert with environmental performance and social responsibility. It is not just a fad to be considered today and forgotten tomorrow. A culture based on four "core values" of environmental stewardship, safety, valuing all people and business ethics has provided a strong foundation for our commitment to sustainable development.

Conoco has been involved with activities and initiatives around the concept of sustainable development for a number of years. Conoco is an active member of the World Business Council for Sustainable Development (WBCSD) and a founding member of the Gulf of Mexico and North Sea regional Business Councils for Sustainable Development. In 2000, the company has earned the distinction of being a component of the Dow Jones Sustainability Group Index, which tracks the performance of the top 10% of sustainable companies in the world. Oekom Research AG also ranked Conoco number one in 2000 among 23 energy companies in corporate responsibility.

Sustainable development efforts have been focused upon: (1) Improving the sustainability of existing operations, (2) Expanding beyond traditional hydrocarbon businesses, (3) Integrating sustainable development into core business strategy and engaging stakeholders, and (4) Fostering innovation and technology to achieve sustainable growth. A managerial position was created to assist leaders in developing mindsets that will enable sustainable growth. Tools for measuring performance against sustainable development criteria are under development and outside resources are sought to help broaden our perspectives. Operations around the world are identifying better, more sustainable ways of doing business that meet the "triple bottom line" of financial, environmental and social accountability. In addition to evolving business approaches, technology development in areas of carbon fibers, natural gas refining, and environmentally enhanced motor fuels offer exciting prospects to meeting future energy and resource demands. In September, 2000, the gas-to-liquids (GTL) project team was selected by the U.S. Department of Energy as a recipient of an R&D grant under their "ultra-clean fuels" program.

While proud of our leadership role, Conoco is by no means satisfied that we are where we need to be. Our approach is to obtain competitive advantage by growing sustainable businesses and adopting a corporate policy and strategy to achieve this objective.
Estimating kv/kh Ratio for Conductive and Nonconductive Shales and Mudstones
Authors: Kasap Ekrem
Published: December 2007

Numerical simulations require homogenized grid block properties. Often depositional processes build up high, low or no permeability units even on a grid block scale. Anisotropy is a result of homogenization of these laminations and other types of heterogeneity. kv/kh ratio is a measure of anisotropy in absolute permeability. A robust kv/kh ratio is essential for accurate field performance predictions.

Some kv/kh ratio calculation techniques were suggested in the literature for stochastic non-conductive shales. However, the lack of more generalized and simplistic techniques for 3-D numerical models is apparent

In this study, we developed Streamlines, Incomplete Layers, and NTG (Net to Gross) techniques to calculate kv/kh ratio of a 3-D grid block with conductive and non-conductive flow-barriers. A typical numerical grid block was populated with sand and shale intercalations from zero to more than 25% shale volume. kv/kh ratios for 15 cases were calculated with the above analytical techniques. Two shale permeabilities, l.e-4, and 4.0 mD were considered. 15 cases were simulated and results were compared. The comparisons indicate that the analytical methods all gave similar results to numerical kv/kh ratios for impermeable shales. Only Incomplete Layers and NTG techniques yield acceptable results for permeable shales. A field case history match, where NTG technique was used, was also presented.
Producing the Well in Artificial Lift By a Subsurface Compensated Pump: A New Production Method
Authors: Buchman Smil S.
Published: December 2007

This paper presents a new production method in which the reservoir energy spent to lift the production from perforation-depth to the dynamic liquid level is replaced by surface energy, and consequently the well daily rate and cumulative production is increased by 200 – 250 %. The method can be used in any well at any time.

The paper is based on the analysis of how the reservoir energy generated by the expansion of the reservoir fluids is used to produce the well:

PROFITABLE USAGE: Moves the production through the pay zone into the well bore.

WASTEFUL USAGE: Sends the reservoir energy to:Overcome the liquid friction along the production flow path.Lift the production from perforation-depth to the dynamic liquid level.

Present production practice recognizes and reduces only the reservoir energy wasted to overcome the liquid friction through the pay zone by using better and cleaner perforations, acidizing, fracturing, and other techniques. When less reservoir energy is used to overcome the frictions through the pay zone, the well performance, in both rate and cumulative production, is increased.

To date all artificial lifting methods are spending surface energy only to lift the production from the dynamic liquid level to the surface. However, the energy needed to lift the production from perforation-depth to the dynamic liquid level, the largest waste of reservoir energy, is now overlooked and has not been recognized as the most important way to significantly increase well performance. The proposed new production method substitutes the reservoir energy by surface energy in order to lift the production from perforation-depth to the dynamic liquid level. Accordingly the well performance in day rate and cumulative production is increased by 200 – 250 % compared to the actual well performance.

The quickest and easiest way to produce the well according to the new production method, is to run a subsurface compensated plunger pump assembled from the API Spec-11AX parts, and work with the same beam pump. A subsurface compensated pump, is a liquid lifting device, which can not be drawn by the well pressure.
Competency Ingredients for the Successful Petroleum Professional in the New Millennium
Authors: Fattahi B. , Riddle S. O.
Published: December 2007

Against a background of mergers and acquisitions, lean organizations and business demands, today's working environment has become more diverse and far more challenging. Globalization of the industry, the advent of instant communication, and rapidly developing technology, more than ever require today's petroleum professionals to maintain their technical competence, broaden their experience, and constantly adapt to the fast paced work environment. The attributes of petroleum professionals in the new work environment will be different from the traditional ones. Now a host of so-called "soft" skills have gained prominence in today's business environment. Technical competence will be defined by how well results are achieved through effective teamwork, leveraging diversity of perspectives and critical thinking and creative problem solving. Petroleum professionals who can quickly learn and develop these competencies will be in a better position to compete for the most attractive job opportunities.

This paper analyzes the workplace expectations for petroleum professionals and proposes the competency ingredients for career success in the New Millennium.
Massive Propped Fractures to Develop Marginal Sandstone Gas Reservoirs
Authors: Orski K. , Combellas R. , Bagherzadeh B.
Published: December 2007

The Pole-du-Nord Project, offshore Netherlands, covers the joint development of four small Lower Slochteren dry gas bearing sandstone reservoirs. The development scheme is the result of extensive studies to mature an optimized project, taking into account the limited size of the fields, the poor petrophysical characteristics and the reservoirs uncertainties. These fields are located within a circle of 3500 meter (11 500 ft) of radius. The target zone is 60 meters (200 ft) thick and 3700 meter (12000 ft) deep.

Extensive subsurface studies demonstrated that the poor productivity of the exploration wells was explained by facies variations due to sedimentological deposit history. The sedimentary pattern is a mixed fluvial, aeolian deposit that leads to a very heterogeneous multilayered reservoir. The horizontal permeabilities range from 0.01 to 40 mD but the main reserves are located in the poor but thickest fluvial facies, with permeabilities from 0.1 to a 0.5 mD. The drainage of each gas pool by one well was proven with specific stochastic geological modeling constrained by DST results and full field flow simulation.

The development with one central platform was by far the most economical solution. The key factor was the well productivity enhancement.

Various possibilities to enhance productivity were screened, including a horizontal multi-fractured well. The selected solution which honored all the constraints (technical feasibility, minimum cost, initial rate and reserves whatever the reservoir heterogeneity) was a massive fracture treatment on two wells out of the four. The target fracture length was 50 meters (820 ft). The uncertainty in the stress distribution across the reservoir made frac height growth prediction tricky and led to several provisional treatment scenarios.

The target drawdown on reservoir was 200 bar, which made the resin coated proppant selection a crucial point.

The S shape profile was also a drilling challenge regarding the departure of these wells.

This paper presents the project reasoning process, the treatment preparation (including a specific care on the fluid formulation and its interaction with the resin coated proppant) and the fracture evaluation.

The project is a technical and economical success. The lessons acquired in Pole-du-Nord will be a reference for further marginal gas field development in this area.
CO2 Acidizing Treatment of a Deepwater Subsea Well without Intervention
Authors: Buie Paul , Ritter Wes , Ellis Richard C.
Published: December 2007

An openhole gravel-pack completion was performed in the vertical section of a high-permeability oil formation in a deepwater subsea well. The openhole section was drilled with a synthetic oil-based drill-in fluid and completed with a circulating gravel pack using weighted brine.

Initial production was satisfactory at over 10,000 BOPD. However, 11 months later, after a constant decline in production, the well was producing at an unacceptable rate of 3,000 BOPD. Analysis of the formation mineralogy from an offset well in the same formation indicated a strong tendency for fines migration. In addition, there was concern that filter cake from the synthetic drill-in fluid could still be in place and would provide some restriction to optimum production rate. A HF sandstone acidizing treatment incorporating a CO2 preflush process for matrix oil well stimulation was recommended.

Since the well was a deepwater subsea completion, a rig intervention would have been extremely expensive. Therefore, the possibility of performing the matrix CO2 treatment through the flow line from the TLP floating production facility was reviewed and determined to be feasible.

Procedures incorporating the use of the permanent downhole pressure gauges for rate and pressure control resulted in restoring a sustained production rate of 7,000 BOPD. The procedure and steps used for determining and executing the final treatment design will be presented.
Artificial-Lift Systems Pattern Recognition Using Neural Networks
Authors: Ocanto Leonardo , Rojas Alexander
Published: December 2007

Artificial Neural Networks (ANN) are computational algorithms well suited to identify non-evident regularities and correlations in data. ANN are especially useful when there is missing or noisy process data, and when a mathematical model of the process is not readily available, as is the case with some Artificial Lift methods. Some ANN models exhibit excellent dimensionality reduction and visualization capabilities, mapping non-linear statistical relationships between high-dimensional data into simple geometric relationships, preserving the most important topological relationships of the data set. Thus, useful insight on the behavior of the process under study can be gained and used in its analysis and diagnosis. All this makes ANN a very useful tool in the exploratory phase of data mining. Results of several case studies applying ANN in pattern recognition of some Artificial Lift systemas are presented.
ESP's Application in Oritupano-Leona block, East Venezuela
Authors: Novillo Gumersindo , Cedeño Herman
Published: December 2007

This paper describes the successful experience obtained in using electro-submersible pumps (ESP) in the production of abrasive and corrosive fluids. The study covers 60 wells operated by the Consorcio equiped with ESP's in Oritupano–Leona field, States of Anzoategui and Monagas, East Venezuela.

The influence of the reservoir on the pump run life is reviewed. Currently, 46% of the total oil is produced through ESP's, the first instaled in 1996. Most of the failures are related to sand production and corrosion. Since the start of this program, pulling jobs due to ESP's failures have been significantly reduced, due to practices that increase the run life of the pumps, including: -a start-up procedure to reduce fines production-an exhaustive, teamwork based, study of the failures-the use of special abrasion / corrosion resistant materials

All of these factors combined have allowed to optimize the application of ESP's in this field. Details of the various methodologies used to achieve the optimization of the ESP system in Oritupano and Leona fields are presented.