bluuebunny/crossref_metadata_2025_split huggingface dataset:
Combination of Straight Hole Drilling Device, Team Philosophy and Novel Commercial Arrangement Improves Drilling Performance in Tectonically Active Region
Authors: Barnes Michael , Vargas Carlos , Rueda Fernando , Garoby Juan , Pacione Mario , Huppertz Albert 
Published: December 2007

Abstract
Drilling through the complex overthrust geology associated with the Andes foothills of Northern Argentina and Bolivia presents a number of distinctive challenges. Formations in the upper hole sections (22" and 16") are typically hard, abrasive and prone to loss circulation. Historically, these intervals are particularly problematic and are responsible for major problems such as low penetration rates, hole deviation and frequent drill string failures.
While planning a well in this area, a detailed analysis of drilling performance, mud logging and wireline data from offset wells was conducted. This analysis helped identify potential problems and led the operator to set objectives for the upper hole sections of achieving the highest penetration rate possible while maintaining a near-vertical wellbore.
A strategy was developed to address the anticipated challenges. The plan had three main components including the application of a Straight Hole Drilling Device (SDD). The contract for its use was a novel combination of lump sum and incentive payment that effectively aligned the commercial objectives of the service company and the operator. Finally, the operator implemented a philosophy of teamwork that challenged all personnel involved in the well to identify the best drilling performance achievable with current technology and also feel committed to deliver a significant performance improvement.
The 12-1/4" hole section was drilled to 4700 meters (m), in only 161 days, 30 days less than the best-offset performance and 49 days less than the regional average. The 9-7/8" production liner was successfully run and cemented at this depth. Wellbore quality was also significantly better than in previous wells as shown by comparing wellbore displacement at 2300m, less than 20m with use of the SDD tool as compared to almost 150m in the closest offset. This displacement was achieved with lower average dogleg severity, which contributed to reaching the 9-7/8" casing point without any drill string failures or washouts. These achievements, along with the fact that no accidents were incurred from spud to total depth (TD), has established the new "best in class" benchmark for drilling operations in the area.
This paper describes the application of this innovative technology in addition to the drilling and novel contracting practices. The authors will outline these agreements and their advantages then highlight opportunities for further improvement.
Formulating a Safety Management System for a Global Drilling Organization
Authors: Jenkins R. W. , Garcia H. A. 
Published: December 2007

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

AbstractEcological 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

Abstract
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 &gt; 175 °C, P ~13,500 psi, TDS &gt; 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 (&gt; 25 m/s) and high shear stress (&gt;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

Abstract
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

Abstract
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.