bluuebunny/crossref_metadata_2025 huggingface dataset:
Guidance Manual on HSE
Authors: Milne D. J. , Willink C. A. Tjeenk , Sexton K. , Stockley J. D.
Published: December 2007

This paper describes the SIPM1 centrally produced Safety Manual issued as a prime reference to Shell2 Exploration and Production Operating Companies worldwide. It discusses the decision to update such a document at a time when a Company standardisation spearhead is directed at reducing internal standards and adopting where possible internationally accepted standards and guidelines and also when more HSE3 guidance literature is available in the industry.

The revised Manual will address Health, Safety and Environmental issues and provide support to Operating Companies in the development and maintenance of their HSE Management System and Safety Cases. The Shell Exploration and Production Business Model (EPBM) of activities is used in the Operating Companies to define the business and is used together with hazard management techniques to identify the critical areas of risk to be managed. The EPBM also provides a hierarchical structure for documentation into which guidelines such as the HSE Manual can be placed. The sections of the HSE Manual are prepared by custodians from the relevant business areas ensuring that the responsibility for HSE remains in the respective disciplines and that the sections are transferable to other documents.

Most importantly, the HSE Manual together with a document management system provides the central framework for feedback and improvement for HSE matters from operations worldwide.
Respirator Safety During Oilfield Servicing Operations
Authors: McCrary J. B. , Sanders J. R.
Published: December 2007

Respiratory safety in the oil field has become an ever-increasing concern. Numerous chemicals are used for well stimulation which present significant health hazards. This paper will outline the necessary elements of a respiratory protection program (RPP).
Monitoring, Process Design, and Formulation Ensures Operators Good Health
Authors: Dewprashad Brahmadeo , Sanders Johnny , McCrary Joel , Murphey J. R.
Published: December 2007

Resin-coated proppants are used in hydraulic fracturing treatments to increase the permeability of the propped bed and/or to reduce proppant flowback. Traditionally, proppants have been precoated in a factory with a resin, taken to the field and used to treat wells with BHT's of 160°F to 325°F. To complement this process, a novel liquid epoxy resin system which can be used to coat proppants in the carrier fluid as they are being pumped downhole, was developed. Proppants, coated with this formulation, can be used to treat wells with BHT's of 75°F to 325°F. Figure 1 shows a schematic of the process. The resin and hardener (caring agent) are mixed and injected at a fixed ratio into the gel which then enters the blender tub where it is thoroughly mixed with proppants. This process minimizes workers exposure to chemicals and has several other advantages.

Exposure to high levels of many of the chemicals commonly used in resin formulations is considered a health risk. However, a formulation which has minimal health risks but optimal performance was developed. Chemicals which have been routinely used in resin formulations, were substituted with novel and less hazardous analogues. In one case, a combination of analogues was necessary to match the performance of the component they replaced.

The formulation was successfully used to treat a number of wells in the Williston Basin of the USA resulting in a several-fold increase in production in each case. The following additional steps were taken to minimize workers exposure to the chemicals used: (1) operators were educated on any adverse health effects of the chemicals used and the proper procedures to prevent exposure, (2) chemicals were transferred directly from storage drums to tanks used during the process in a completely closed system at the district office where conditions are more controlled, and (3) Tyvex coveralls, butyl rubber gloves, and organic vapor/acid gas respirators were provided to operators. Monitoring was done randomly to determine the effectiveness of the steps taken to ensure the operators good health. Their exposure to Chemicals A, B, C, and D in the formulation/fluids was determined by using surface wipes of equipment and skin wipes of operators as well as by air quality monitoring with passive organic vapor monitoring badges and Chemical A sample media. The results, obtained during a particular treatment and given in Tables 1 to 3 indicate exposure levels well within the acceptable levels. Monitoring for these chemicals was repeated during another treatment. Again, exposure levels were within the acceptable limit.
EIA as an Integrated Management Tool: Case Study
Authors: Bakar M. J. , Cramwinckel J. F.
Published: December 2007

Brunei Shell Petroleum, as a major operator for exploration and production of oil and gas in the country, has a policy to give the highest regard to the protection of the environment. Minimisation of environmental impact throughout the life of a project, from inception to abandonment, is a requirement of this policy. As a tool Environmental Impact Assessment (EIA) is performed before entering new projects and major modifications to existing facilities.

The process of an EIA can be broken into four major stages with feedback or corrective loops during the planning and execution of the activity, and after closeout of the project. The flow of environmental and business activities is fully integrated, (Figure 1).

Firstly the Environmental Profile and the Technical Profile of an activity need to be identified. A Preliminary EIA is prepared from this information.
Occupational Health Practice in Confined Space
Authors: Darmansjah Nuch
Published: December 2007

PT. CALTEX PACIFIC INDONESIA is a production oil company located in Riau Sumatra, with the average production of 700,000 barrel of crude oil per day and total employees of around 6200 excluding contractors. In its daily activities a number of facilities or work places are considered as Confined Spaces. These facilities among others are: Vessels, Gas Turbine, Tanks, Pipeline, Pits, Gas Boots, Stacks, Tunnels, Towers, Tank Cars/Truck.

Since Confined Space has a different work environmental condition, a special attention should be taken to protect the workers in doing their job from any health hazard or unsafe condition/act. This corresponds with CPI statement values in its vision and mission stating that CPI will maintain a safe and healthy environment for employees, contractors and dependents.

Confined Space is a space with a relatively small volume of unfavorable natural ventilation where the workers enter for the purpose of doing some maintenance, repair or cleaning.

The purpose of this study is to evaluate the impelementation of Occupational Health and Safety practice among CPI employees and its contractors. And the scope of the study is the workers who work in Confined Space in Minas and Duri districts within CPI area.

In this study we have collected data from wash tank, shipping tank and some tank farm within CPI area of operation. The main problems encountered by the workers while doing their job are hot temperature, lack of oxygen, some hydrocarbon vapor and the possibility of accident because of slippery condition or fire that can be caused by crude oil if they don't clean it thoroughly. The workers consist of contractors and CPI employees with their age varies from 25 - 45 years. Work procedure has been established by Environmental Health Department and Safety Department in anticipating this situation.

Water supplement, extra feeding and strict supervisory are conducted in order to protect the workers from any possible injury or health ill effect. Some improvement must be implemented especially for the contractor's workers as follows:

Health certificate or Physical examination should be available beforehand. First aider should be available at any time during working period. First aid kit and emergency procedure should be established accordingly. Health education and safety information must be conducted regularly for the supervisor and the workers.
Polymerizable Ultra-Thin Films: A New Technique for Fines Stabilization
Authors: Sharma B. G. , Sharma M. M.
Published: December 2007

The detachment and migration of colloidal particles is an important cause of permeability decline in the near wellbore region. It is shown that polymerizable ultra thin film can be utilized to immobilize fines on pore surfaces. The Surface Adsorption Polymerization (SAP) process developed here is a three step process requiring a sequential injection of a specific concentration of the surfactant, monomer, and initiator. An ionic surfactant is first adsorbed on the solid substrate or the porous medium. In the second step, a monomer is injected that preferentially resides in the surfactant layer. In the final step, an initiator is used to polymerize the monomer on the surface to form a solid ultra thin film which is very stable and effectively holds the colloids on the surface.

There are three major advantages of such a treatment. Firstly, there is a great deal of flexibility in the choice of monomers and surfactants used so that the mechanical and chemical properties of the film, can be tailored to meet the needs of a particular application. Secondly, when applied to porous media or microporous membranes the ultra thin film does not cause pore closure. The film is extremely thin and the thickness of the film can be controlled by using appropriate concentrations of the monomer and surfactant. Lastly, the polymerization does not occur in the bulk solution, resulting in minimal waste or damage caused by polymer formation in the bulk solution. The SAP process can be potentially applied to stabilizing fines in high rate producers, as a post flush after acidizing and in specialized applications such as steam huff and puff wells.
Effect of Incompatibilities Caused by Fluids Filtrates on Formation Properties
Authors: Gharat Sandeep , Azar J. J. , Teeters Dale
Published: December 2007

Incompatibilities between drilling fluid filtrates and formation connate fluids are believed to cause changes in rock wettability and hence impair production for a given reservoir rock.

This paper summarizes test results and analysis of an experimental study to systematically assess the effect of incompatibilities on rock wettability and in turn on its permeability. The rocks considered are dolomite, limestone and sandstone. The parameters that were studied are the ph, monovalent to divalent cation ratio, total cation concentration (salinity) and the drilling fluid surfactants. The Dynamic Wilhelmy Plate Technique was used in the measurement of wettability changes. The analysis of test data was conducted using a defined deviation number that allowed quantitative evaluation of the various effects that were considered in the study. Results have shown that the most significant in rock wettability changes are the surfactants in the drilling fluids.

Dolomite rock had the maximum reduction in water wetness when surfactants are absent, while the reduction is about the sameforall rocks when surfactants are present. Also, among all five water-base muds studied, the calcium treated gypsum mud had the least water wetness.
Minimizing Formation Damage to Gravel Packs: Laboratory and Field Case Studies in the Battrum Field
Authors: Bennion D. B. , Sanders Ron , Thomson W. S.
Published: December 2007

Gravel packs are commonly used to minimize sand production in unconsolidated sandstone reservoirs. The migration of particulates and fines into the gravel packs often has a severely reducing effect on the permeability of the packs and the subsequent productivity of the well. Detailed laboratory studies were undertaken using 12/20 and 20/40 mesh silica gravel to ascertain the optimum gravel size to minimize formation damage to gravel packs in the Battrum field.

The Battrum field is a shallow unconsolidated sandstone reservoir located in Saskatchewan, Canada, producing a low API gravity crude oil over an area of approximately 3900 hectares with 180 active injection and production wells. Currently a large portion of the field is under enhanced recovery using a commercial scale in-situ combustion technique. The results of detailed laboratory studies, including detailed size and sieve analysis of the formation, classification of the different lithologies and detailed laboratory tests to investigate at reservoir conditions the flow of gravel and fines into different sizes of gravel packs are documented. Tests include detailed petrography and computerized petrographic image analysis on actual sections of gravel and formation sand interfaces and illustrate the mechanism of fines entrainment in the gravel packs and provide associated permeability reduction data. Details of field gravel pack treatments are also provided in the paper. Test results indicated an increased propensity for gravel pack plugging in the coarser (12/20) mesh gravel in comparison to the 20/40 mesh gravel. Simultaneous multiphase flow of both oil and water was also found to have an increasing effect on rapidity and severity of apparent plugging. The results presented provide insight into optimum gravel to sand sizing ratios for this field and have potential application to other similar reservoirs.
Degradation Mechanisms of the HEC Gel in Connection With Prevention of the Formation Damage: Part I
Authors: Hayatdavoudi Asadollah , Mehdizadeh A. M. , Caothien Scott , Malbrel Chris
Published: December 2007

In the course of a recent investigation on the formation damage associated with HEC gels, we found no published comprehensive work on the interactions between HEC gels, the geochemistry of the formation, and the gel breakers. Recognizing this lack of information and in view of the popularity of HEC gels as viscosifying agents, we have embarked on sharing our findings with the oil and gas industry in several parts, the first of which is presented below.

In this paper, we will review fundamentals on cellulose chemistry and cellulose quality as related to the manufacturing of HEC polymer, the formation of "fish-eyes" and "micro-gels" and the degradation mechanisms of HEC gels by temperature, acids, bleach, and enzymes. Finally, we will present practical measures to alleviate formation damage. These measures includes adequate polymer and gel quality control (MS/DS ratio) as well as the implementation of proper field practices (control of the pH, filtration of the gels, etc.).
Correcting a Serious Procedural Flaw in Laboratory Studies of HEC Gel Return Permeability in Connection With Formation Damage: Part II
Authors: Hayatdavoudi Asadollah , Ghalambor Ali
Published: December 2007

In the course of our laboratory investigation of HEC gel return permeability, with regard to formation damage (see also, SPE #27366) we found that the gel quality assessment, as related to the gel breakback is based on the ancient displacement studies related to reservoir engineering where flow through a Berea core is maintained at constant pressure and later the change in permeability is calculated as a percentage of the initial permeability. Furthermore, and to the detriment of some service industries, we found when these procedures were followed exactly as written by some well-intentioned spec writers, some of the tests qualified the HEC gel sold by one service company, while the same HEC gel sold by another company failed the same qualifying test badly. In fact, we witnessed HEC gel return permeabilities ranging from zero to about 13%. Appreciating the dilemma of the service industry within the context of "hard times", the authors, at their own initiatives, reconfirmed their initial findings: That is the main cause of damage could be only understood by a broad, interdisciplinary petroleum engineering approach, rather than through ordinary reservoir engineering practices. Our approach was to examine simultaneously the cellulose backbone chemistry of the HEC, the geochemical engineering aspect of the Berea core, the flow through it and interaction of gel breaker with HEC and the mineral contents of the Berea core.

On the basis of our findings, we concluded that damage to the Berea core resulted from: (a) the hydration and/or oxidation of iron minerals in the core, namely iron chlorite, ilmenite and iron (II) oxide, (b) most of the minerals reacted with the HEC gel breaker (in this case, sodium hypochlorite), (c) the transport and entrapment of hydrolyzed/oxidized particles of 0.4 to 1.0 micron by high viscosity gel, and (d) the appearance of newly formed clay particles (most probably kaolinite) at the pore throats. These new particles could have originated from the breakdown of chlorite clay after release of iron and/or from K-feldspars.

In order to aid the service industry, we reported that a serious procedural flaw in HEC gel quality control must be corrected before running a core flow test by following two simple steps: (1) If strong breakers are chosen for quick degradation of HEC gel, they must be compatible with mineral contents of the core, and (2) HEC gel/breaker/mineral contents of the core must be considered as one system. Following these simple corrective steps in our first test, we chose a "very" clean Berea core with extremely minute amount of hydratable iron sources which could react with sodium hypochlorite. In that experiment we qualified the HEC gel with nearly 90 - 95% return permeability. This was the same HEC that had failed the test previously.
An Assessment of Formation Damage: A Case Study for the Cusiana Reservoir, Colombia
Authors: Blosser W. R. , Mujica Santiago
Published: December 2007

The Cusiana reservoir in the Casanare region of Colombia is currently being appraised and developed. Cost effective development of the reservoir will be dependent on applying optimum drilling and completion practices. The purpose of this poster session is to provide a case study history for the approach and evolution of the project as it pertains to attaining an improved understanding of formation damage mechanisms.
Hydraulic Fracturing of High-Permeability Formations to Overcome Damage
Authors: Parker M. A. , Vitthal Sanjay , Rahimi AI , McGowen J. M. , Martch W. E.
Published: December 2007

Gravel pack operations in poorly consolidated, high-permeability formations are often plagued by relatively low production results, which are caused by the constraints of radial flow, damage to the formation and damage to the gravel pack caused by the treatment fluid. Hydraulic fractures will alter the radial flow for improved production results and will reduce the effects of formation damage caused by the treatment fluid.

Data have been generated with several fluid systems that show the damage to the permeability of three different rock types. Fluid loss test results show the expected fluid loss performance of the different fluids. Calculations from recent work are used to show that viscous fluid invasion is also a mechanism for fluid loss control. Fracture conductivity data are provided for 20/40 mesh sands to show performance with the fluids tested. Additional conductivity data with 40/70 mesh sands illustrates the fact that small size gravel pack sands may not provide adequate conductivity for fractured well production. Reservoir simulations compare well performance based on the data provided here.
The Effect of Fracture and Formation Flow Variables on Proppant Pack Cleanup: An In-Depth Study
Authors: Frederick J. M. , Hudson H. G. , Bilden D. M.
Published: December 2007

For many years retained proppant pack conductivity has been used as a major tool in the prediction of optimizing production. As a result, standardized methods of performing proppant pack conductivity tests have been developed and published. The objective of this study was to determine the difference in near wellbore, mid-fracture, and "tip" cleanup of polymer in the proppant pack during fracturing treatment flowback. To ensure optimum formation production, consideration of polymer cleanup between the mid-fracture and the "tip" is necessary to limit the possibility of production limitations due to pressure drop along the fracture length. Cleanup of a proppant pack is influenced by many factors: fluid leak-off, fluid and breaker chemistry, formation mineralogy, fines migration (i.e. crushed proppant and fluid loss additives), temperature, pressure, etc. This study focused on the different cleanup effects determined by the rate and direction of flow in the proppant pack.

The testing methodology used in this study focuses on evaluating the different parameters encountered during actual fracturing treatment flow-back: Removal of filtercake and insolubles due to breaker.Rate of removal of filtercake and insolubles due to flow rate in the fracture.Rate of removal of filtercake and insolubles due to rate of flow through the filtercake into the proppant pack.Rate of removal of filter-cake and insolubles due to interactive flow directions.
Formation Damage of an Unconsolidated Reservoir During Steamflooding
Authors: Hajdo L. E. , Clayton C. A.
Published: December 2007

One of Mobil's principal heavy-oil reservoirs, the Miocene Monarch, in the South Midway-Sunset Field, Kern County, California, is a thick sequence (400 ft.) of unconsolidated deep-sea turbidite gravels, sands, silts, and muds. Disappointing steam injection rates and poor production responses over the anticline prompted a laboratory and simulation investigation of the causes of the shortfalls. High-temperature coreflood experiments were conducted on selected facies, backed by liquid and solids analyses. The experiments showed that fines migration and smectite clay swelling are the primary causes of the restricted injectivity and quantified the severe damage.

Numerical thermal simulators lack the ability to model dynamic formation damage, but it was necessary to capture this progressive loss of permeability to match the field performance. Using a commercial simulator, we represented our laboratory data through the artificial regulation of the temperature dependence of the relative permeabilities. With this, and the recognition of some secondary effects, a very good history match of wellhead rate and pressure responses was achieved. The work shows that the use of standard nitrogen permeabilities gravely over-estimates field performance in this type of reservoir.
Formulation and Field Trial of a Nondamaging, Subhydrostatic Oil-Base Workover Fluid
Authors: Kohli B. S. , Raghunandan _ , Kumawat K. R.
Published: December 2007

The significant formation damage with the use of conventional workover fluids due to filterate invasion of water sensitive zones in the wells having subhydrostatic reservoir pressures can be avoided by the use of nondamaging subhydrostatic workover fluids. New formulations of oil-base workover fluid with minimum specific gravity (0.86) and requisite Theological properties were developed through extensive laboratory studies by using LSHF HSD or a mixture of HSD and stabilised connate crude oil (1:1) and OBM chemicals. The formulations were subjected to field trial in subhydrostatic wells of the Kalol oil field in Western India. The bottomhole studies and / or production performance of the wells worked over with this system, have indicated revival of the wells to their optimum production, which would have been impossible otherwise. The success of the system has found its preferential use for workover operations at all subhydrostatic wells in the Kalol oil field.

The oil-base subhydrostatic fluid system has been introduced for the first time in ONGCL, India. Economically, it is very much viable due to its reusability at different wells. The use of stabilised /treated connate crude oil in equal parts with HSD further reduces the cost of the system with additional benefit of its wax dissolving capacity at perforations.
Polymeric Flocculants Prove Most Effective Chemicals for Wellbore Cleanup Operations
Authors: Holland Brian , Cooksley Timothy , Malbrel C. A.
Published: December 2007

Upcoming zero discharge regulations, high rig time cost, and low oil prices are motivating the industry to look for faster, more effective displacement that reduce the volume of fluid to dispose and decrease circulation time.

A field study conducted in South East Asia showed that more effective displacement can be achieved by adding to the circulating fluid a polymeric flocculant instead of the commonly used surfactants.

A laboratory investigation was undertaken to understand the fundamental mechanism governing well bore clean-up. Its conclusions are as follows: under the highly turbulent flow conditions reigning during displacement operations, saltwater cleans metallic surfaces as well as surfactant solutions;polymeric flocculants form larger and stronger aggregates of solids than surfactants which can withstand better the stresses associated with turbulent flow. This improves the sweeping efficiency of the circulating fluid by increasing fluid drag force on the solids.
A New Development in Gravel Packing
Authors: Nelson Allen C. , Smith Donald M.
Published: December 2007

Gravel packing in wells is made necessary by the need to maintain control of unconsolidated sand formations. The use of gravel packing as a purposeful technique in oil wells has been known at least since the 1930's. Methods of achieving competent gravel packs have varied with time and from place to place. Technical improvements have been made steadily through the years. As with many other processes used in wells, the effectiveness of the developed methods has had to be measured mostly indirectly, by observing results. Direct observation or measurements to monitor the placement or subsequent competency of the gravel pack in detail have not been possible.

An increasing number of fields have been waterflooded in recent years resulting in greater sand control requirements. Higher fluid velocities have made it necessary to gravel pack zones which did not require elaborate sand control measures under primary recovery.

Although operating costs and liner failures have been reduced by gravel packing, a need still exists for improvement. This paper presents completion methods that have been developed and tested wherein rates of 35 B/D/ft. of liner or greater over long formation intervals can be achieved without sand problems. Over 110 wells have been completed using these techniques since June, 1967, with no sand control failures to date.

Critical specifications have been developed involving gravel quality, gravel-sand size ratios, liner slots, hole size, completion fluids, cleanup procedure, cleanup chemicals, and mechanical procedures. Some of these items have been discussed extensively in the literature, others are innovations.
Effects of New Generation Drilling Fluids on Drilling Equipment Elastomers
Authors: Badrak R. P.
Published: December 2007

Environmentally safe drilling fluids have been the subject of considerable interest from governments, operators, oil companies and drilling fluid manufacturers. The use of these drilling fluids has been increasing, this has been especially true for offshore drilling operations.

Drilling fluids can chemically alter the properties of elastomers used in drilling equipment, severely affecting life and function. The products affected include blowout preventers (BOPs), pulsation dampeners, downhole mud motors and drilling bits. This study centers on the effects of selected environmentally safe drilling fluids on BOP and pulsation dampener elastomers.

The properties of these elastomers are presented before and after drilling fluid exposure. The property changes were evaluated with respect to equipment function and performance and exposure time. A wide variation was found in property changes which were dependent upon elastomer and drilling fluid composition.

The performance of elastomers in drilling fluids is strongly dependent upon drilling fluid Chemistry, operating temperature and the type of elastomer chosen for service. Caution and testing were recommended when selecting environmentally safe drilling fluids and compatible elastomers.
A Novel Design Bl-Center Bit Successfully Drills Deep Exploration Well Off the East Coast of Trinidad
Authors: Kalloo C. L. , Attong D. J. , Bickraj Ramsingh , Steele H. E.
Published: December 2007

This paper discusses the application of a novel design two-piece polycrystaline diamond compact (PDC) bi-center bit which was successfully used to drill a deep exploration well, off the East Coast of Trinidad.

New records were achieved on this well by using four different bi-center sizes ranging from 20 inches to 12.25 inches to drill and underream over 10,000 feet of hole. This constitutes the largest and longest section of hole ever drilled with bi-center bits.

Several advantages were realized with the application of this novel design two-piece bi-center bit. The most significant being the elimination of the side loading on the pilot bit. Other advantages include the reduction of drilling torque and the ability to interchange pilot bits.
Gulf of Mexico Mobile Rig Mark Upsurge: How Long Will it Last?
Authors: Plamondon W. N.
Published: December 2007

At the current time, the best offshore rig market in the world is in the U.S. and Mexican Gulf (Bay of Campeche). Will we soon have an oversupply with a continuing return of units from overseas or will there still be a shortage?

The increase in the natural gas prices has driven the U.S. Gulf rig market. Mexico has a great need for additional oil supplies and natural gas. There are currently ten rigs owned by U.S. Contractors drilling in the Bay of Campeche.

For years U.S. oil and gas reserves have been declining. The gas bubble has virtually disappeared. How much activity will it take to reverse the trend and to increase reserves? Most important, will the economic conditions continue to be viable?
A Systems Approach to Downhole Adjustable Stabilizer Design and Application
Authors: Underwood L. D. , Odell A. C.
Published: December 2007

This paper discusses the applications where existing downhole adjustable diameter stabilizers have proven to be beneficial, then identifies additional applications where improved features or capabilities will increase the utility of adjustable stabilizers. Using a systems design approach, those features and capabilities have been incorporated into a new adjustable stabilizer, which is currently under development. Capabilities include a greater range of diameter adjustment, multiple positions, and verifiable twoway communication. The design and construction which makes those improved features possible is discussed. The benefits of those features are demonstrated through computer modeling. Finally, lab and field test results are presented.
A Practical Method To Minimize Stuck Pipe Integrating Surface and MWD Measurements
Authors: Belaskie J. P. , McCann D. P. , Leshikar J. F.
Published: December 2007

A BHA becomes stuck, on average, once for every three wells drilled1. It is very difficult for drilling personnel to monitor sticking during all phases of the drilling operation. There are many situations where monitoring the stickiness of the hole is very difficult. Very often, field crews do not have the time to continuously compute and look at graphs of friction factors, and processing algorithms need to be complimented by automatic warnings. Monitoring sticking while tripping requires knowing the "normal" overpulls, which vary with depth. The authors propose an integrated sticking pipe monitor which automatically calculates friction forces and factors anytime the drillstring is moving, builds normal profiles with depth for comparison and issues alarms to the field crew and driller when sticking is occurring at the BHA.
North Sea Case Histories of Wellbore Stability Predictions for Successful High-Angle Nelson Field Wells
Authors: Ewy R. T. , Ross G. D. , Gast M. R. , Steiger R. P.
Published: December 2007

Eight high-angle (up to 68°) development wells were drilled successfully ahead of schedule and under budget in the Nelson field predrill program. To prevent wellbore instability, which had been experienced on the exploration wells, a new, practical wellbore stability modeling technique was applied. The resulting quantitative guidelines were used to design successful drilling fluid density and casing programs, and well profiles.
Kick and Blowout Control Developments for Deepwater Operations
Authors: Nakagawa E. Y. , Lage A. C. V. M.
Published: December 2007

As the oil industry advances into deep water exploration, the risks of having blowouts increase due to the difficulties related to kick detection and control operation under this condition. New systems, devices and more adequate well control procedures have to be developed to minimize the occurrence of well control problems and blowouts in deep water.

Early kick detection is a key factor for gas influx control. The influx volume has to be minimized for safer well control operations and avoidance of gas in the riser before the BOP is closed.

Well planning also has to be improved. Kick scenarios are being studied with the help of kick simulators for the evaluation and definition of well control procedures. Thus, more realistic kick tolerance margins for the well planning phases, safer well operations and lower costs will be achieved.

Subsea blowout contingency plans are being analyzed for the development of a specific plan. Blowout control methods will be evaluated for specific scenarios. Capping and relief well drilling may be considered as concurrent alternatives to control a subsea blowing well. Topics such as personnel evacuation, oil spill containment, and salvage of the reservoir, rig, and well will also be covered by this plan.

Other aspects to be considered are the development of: (1) a computer system to supervise the BOP to increase its the operational reliability; (2) procedures for minimizing the risks involved during an emergency disconnection in dynamic positioning vessels; (3) a method to eliminate the riser safety margin.

All these studies are being carried out in Procap 2000, a major PETROBRÁS project for deep water exploration and production with the objective of developing full capability to drill and produce in 2000 m of water depth.
Semisub Tender-Assisted Drilling Rigs
Authors: Lorehn O. L. , El Sharkaway A. E.
Published: December 2007

Several major oil companies in the Far East have been having considerable downtime during moving operations with mono-hull tender rigs, particularly during the typhoon season. The use of semi-submersible drilling rigs converted to act as a tender to a platform drilling rig is an excellent replacement for the mono-hull tender and has several significant hidden advantages as well.

This paper compares a mono-hull tender to a semi-submersible in all aspects and describe the modifications that will generally be required for converion. Several significant advantages have been discovered that were not obvious when this solution was first considered. In addition to almost eliminating downtime during erecting, the semi can erect faster, do it safer, and in deeper and rougher water.
Volume Requirements for Directional Air Drilling
Authors: Guo Boyun , Miska S. Z. , Lee Robert
Published: December 2007

It is highly desired to develop a simple and reliable method for determining the air volume requirements for directional air drilling operations. Using Niku-radse's friction factor correlation for turbulent air flow, Angel's empirical model for determination of air volume requirements for vertical well drilling is modified and extended to deviated and horizontal well drilling. The new model is verified by field data taken from air drilling operations. The result given by the this model matches Amoco's experience very well in a wide range of well geometry for vertical wells. A series of charts which are similar to Angel's is presented for quickly determining circulation rates for vertical and directional air drilling operations.
The World's Most Advanced Platform Rig Troll
Authors: McGill John
Published: December 2007

The Troll Phase I platform drilling facilities will be one of the world's most advanced drilling rigs with respect to remote operation of vital drilling equipment. The functions have been selected to remove the human element from the operational envelope which is statistically the most accident prone area, and to meet Norwegian Petroleum Directorate regulations.
Optimization of Rotary-Shouldered Connection Reliability and Failure Analysis
Authors: Baryshnikov Anatoly , Ligrone Angelo , Ferrara Paolo
Published: December 2007

IADC and SPE Members

This paper presents a case history of drillstring failures in some ultradeep wells drilled in Italy. A new method to optimize the selection of the most suitable Rotary Shouldered Connections (RSC) and failure analysis is developed by using a new factor identified as Fatigue Strength Ratio (FSR). The concept of FSR is mainly based on information available from full scale fatigue tests of RSC's. On the basis of A.8.3 paragraph of API RP 7G this work suggests a wider discussion about RSC's operating limits under combined various static and dynamic loads. A better understanding of static and fatigue characteristics of connections is provided along with plots and equations.

Introduction

Due to the increase in well depths and the complexity of drilling operations to be faced in northern Italy, the control of drillstring element serviceability is becoming more and more important. In fact, apart operating risks, the cost of a complete drillstring can be an important economical factor. RSC's are the weakest items in terms of reliability especially the drill collars' ones; thus the necessity to have a better understanding of their behaviour under applied static and dynamic loads.

Early in the eighties, the discovery of Villafortuna-Trecate field, - north west of Italy, lead to the drilling of ultradeep wells. Operating conditions are extremely severe, since along with the considerable depth of the wells (from 6000 m to 7000 m), high temperatures (up to 180 C) and pressures (over 1000 bar) have to be faced. Furthermore, the drilled formations are very hard and abrasive, while the bottom hole environment is very aggressive due to the presence of H2S and CO2. In such operating conditions an abnormally high occurrence of drillstring failures was recorded. A survey based on the first 7 wells showed that most of the failures took place in the BHA (77%, not including HWDP). A significative number of failures was detected in the drill collars (41% of the total) and the combinations 8" DC with 6 6 / Reg and 9" DC with 7 / Reg gave the highest number of failures (50%), mainly in the last engaged thread of the box (see Fig. 1).

So, in order to decrease the number of drillstring fatigue failures non standard inspection procedures were introduced. Non destructive tests (NDT) of drillstring elements were set at 300 hours of rotation for the BHA, 600 hours for HWDP and the first 20 DP's and 1500 hours for the remaining drillstring. A further survey demonstrated that, after the NDT's procedures' were introduced, the number of failures was actually decreased. However, a high number of cracks -was detected during NDT's (Fig. 2).

P. 935^
Geospatial Modeling Techniques for Understanding Internal Geometries of Complexly Faulted Reservoirs
Authors: Belcher R. C.
Published: December 2007

One of the many challenges in reservoir characterization is the problem of accurately defining, visualizing, and understanding spatial relationships between faults and structural horizons. With the use of new threedimensional geospatial modeling tools geologists, geophysicists, and engineers are able to build geologic models which can be used to verify data interpretations, spatial relationships, and internal geometries of complexly faulted reservoirs.

This paper briefly describes recently developed geospatial modeling technology and the process by which three-dimensional geologic models are constructed. Examples from various studies are presented.
Understanding Borehole Stability: The Power of Computer Animation
Authors: Kwakwa K. A. , Batchelor A. S. , Curtis R. H. , Lanyon G. W. , Batchelor J. W.
Published: December 2007

Well design and planning procedures that integrate mechanical borehole stability analyses can improve overall drilling efficiency and reduce lost time costs substantially. The two key requirements needed to achieve these potential savings are, firstly, effective modelling processes that use all the available information from existing wells and, secondly, communication of the end results in a form that is easily applicable at field level. In this paper we describe both a model and communication method that have been used for several years with considerable success. The end products from such analyses are presented in easily understood graphical and numerical formats developed in response to the requirements of several operators. The computation and presentation are entirely computer-based and are an example of an application that can be incorporated readily into existing computer aided design systems within the industry with the goal of reducing drilling costs significantly.
Expert System for Corrosion Evaluation and Material Selection in Oil and Gas Wells
Authors: Kopliku Ardian , Bazzoni Bruno , Condanni D. L.
Published: December 2007

This paper deals with an expert system developed for the assessment of fluid corrosivity in oil and gas production wells and for the selection and evaluation of metallic materials. Main aims of the system are: corrosion assessment, material selection and compatibility evaluation, economics, risk assessment, analysis of suitable corrosion control methods, cost comparisons. Accordingly, the system has been developed by individual specialist modules, able to provide the user with some partial answers (such as corrosion rate, likelihood of localized corrosion, stress corrosion cracking susceptibility, suitability of a material, etc.) or the final solution (i.e., the corrosion control method). An explanation module visualizes the rules utilized and allows to create a file for each session and to print a report containing all input data and the results obtained. Emphasis has been devoted to the interfaces to be as much as possible user-friendly. For the development of the system, a commercial shell has been used, suitable to run on personal computers.
The Geostatistical Toolkit: Using Advanced Visualisation to Interpret Geostatistical Data
Authors: Franklin D. J. , Crofts H. J. , Watkins A. J.
Published: December 2007

This paper describes how advanced visualisation techniques may be used to link the work of geologists and reservoir engineers, who traditionally view reservoir description in different ways. We outline these two approaches, and show that they fundamentally differ in utilising available data, particularly when there is uncertainty over the reservoir description. We then argue that in such cases the approaches may be linked using geostatistical modelling techniques, and that these techniques are most effectively used in conjunction with advanced 3D visualisation methods. We describe the development and use of one such application, illustrating our description with suitable examples.
Providing Quality User Support
Authors: Flew S. R. , Kneath T. H.
Published: December 2007

This paper discusses the setting up of a Quality User Support system, and the provision of high quality software to the Petroleum Engineering community.

Using our experience in reservoir simulation software as a case history, we review possible problem areas and recommend ways of avoiding them. In particular we investigate techniques and methods to:

maximise the quality of released software train and educate new users in how to make best use of the software answer ad-hoc questions on the use and functionality of the software minimise response time to identify and fix coding errors enhance client liaison.

We detail some of the procedures that we have developed over the last ten years, which include:

strict programming standards and adherence checking change-control procedures for all software updates providing advice based on experience for system configuration logging and tracking of all user requests and problems regularly polling users about the perceived level of support. providing feedback to the development team for improved ease of use and functionality

Finally, we look to the future and predict ways to improve the level and quality of user support.
Monobore Completions for Slimhole Wells
Authors: Robison C.E.
Published: December 2007

The oil and gas industry of today is vastly different from that of 20 years ago. Today 5 climate is one in which operational strategies are being subjected to a continuously-increasing number of stringent controls, imposed by both regulatory and economic constraints. In response the trends worldwide appear to have taken two directions; one concerns optimization of well production but, of fewer wells and the other places impetus on the need for new methods to improve operational efficiency of drilling and completion practices, and thus, make them more economically feasible. This paper discusses a completion concept that can support either trend.

"Slimhole" and "monobore" are completion concepts that were first attempted during the 60's and 70's and have recently gained popularity because of the potential cost savings each offers. The technological advances in equipment technology and in well servicing techniques for each concept provide reasons to adopt these individually as acceptable completion practices. The fact that these recent advances have enabled the two concepts to be combined into one completion system, the combination of which can further enhance production flexibility, provides even stronger support for employing these techniques. The overview presented here will introduce the completion equipment and techniques and the benefits that will help to establish these concepts as routine completion methods.

Introduction

There are many definitions for the terms "slimhole" and "monobore." To simplify the scope of this paper, "monobore" is defined as a completion with a single production tubular bore size from the surface and through the producing zone; and "slimhole" is used to designate a well in which the wellbore has been drilled with the intent to minimize the hole size and subsequent tubulars.
Experience of Coiled Tubing Operations at North Brae, in Deep, High Pressure Corrosive Wells
Authors: Girling S. P.
Published: December 2007

North Brae is the first North Sea gas condensate field to be developed using gas cycling for pressure maintenance and improved recovery. Deviated wells have been drilled to depths of up to 18,900’ MDRKB. Typical shut-in tubing head pressures (SITHP’s) are in the region of 4, 000 psi for producers and 5,000 psi for gas injectors. Moderate concentrations of C0 2 and H2S at these pressures give partial pressures which cause a corrosive environment.

Coiled tubing (C.T.) well intervention in these conditions initially proved to be difficult. Failures of pressure control equipment and. the C. T. itself were encountered. Despite this, upgrading of equipment and improved procedures have allowed implementation of a highly successful C. T. programme at North Brae.

This paper provides information on the operational difficulties encountered, and resulting improvements made to overcome them. It outlines some of the equipment and technique upgrades necessary to ensure efficient and safe C.T. intervention in these difficult conditions.