bluuebunny/crossref_metadata_2025 huggingface dataset:
Hydraulic Fracturing Provides Production Gains in Kalchinskoye Oilfield of Western Siberia
Authors: Kondratoff L.B. , Khasanov R.N. , Budziak J.J. , Hagel M.W.
Published: December 2007

Approximately ten years have passed since western hydraulic fracturing technology was introduced 1 to the oilfields of Western Siberia. This paper examines how that technology is now being applied to the Kalchinskoye oilfield in the southern reaches of the Ob River basin of Western Siberia.

The Kalchinskoye oilfield, being developed through joint venture operations, is best characterized as a low permeability, normally pressured, Cretaceous/Jurassic sand sequence with low gas to oil ratio. This paper discusses reservoir characteristics, well candidate selection, treatment design and performance, and post-treatment analysis. It also details the value of good oilfield operating practices to achieve and maintain fracturing success.

P. 443
Identifying High-Impact Parameters in Stimulation Treatments Using a Trend Empirical Analysis Model
Authors: Grieser Bill , Stark John
Published: December 2007

In an effort to develop best practices for stimulation of a particular zone in a certain area, the completion engineer usually is faced with a number of choices. Ideally, experience will have shown, through production results, a preferred treatment type. However, most of the time the engineer finds conflicting results and uncertain outcomes which make choosing the proper stimulation method difficult.

This difficulty is partly due to the heterogeneity of the reservoir, reservoir-quality differences, and the seemingly infinite number of treatment techniques, sizes, and additives used.

The completion engineer must be able to recognize factors he can control, factors he cannot control, and impacts these factors have on production.

This paper tracks the completion development of 28 wells in the Frontier zone, Fontenelle field, WY. in 1996 and 1997 Descriptions of the different methodologies used and corresponding 90-day cumulative-production results are given.

A data set was created in a spreadsheet format listing pertinent data including porosity-ft, job size, total amount of proppant pumped, gel-system type, breaker amounts, type of breaker, and pH, along with ratio quantities (Ib/gal) for gel, breaker, and proppant.

This data set and production values were used as input information for a trend empirical analysis model (TEAM) to determine what factors, or combination of factors, most affected production results. There was surprise over the identification of some high-impact parameters (HIPs) by the model.

The end result is an analysis tool that helps completion engineers recognize HIPs and the magnitudes of their effects on production.

P. 581
Gas and Gas Lift Wells' Testing With Surface Shut-in
Authors: Al-Haddad S. , Fruge Mike , Frizzell D.
Published: December 2007

The main source for formation damage measurement is transient well testing. The formation damage measured is referred to as the skin factor. To reduce cost and operational risk, many wells are tested with surface shut-in and bottomhole pressure measurement. If properly designed, performed, and interpreted, these tests provide valuable information on the well's skin condition.

Wellbore storage becomes a very important factor with a surface shut-in. In addition to the wellbore fluids' compression and phase changes, temperature effects may be significant and extended depending on many factors including the well's depth. However, field data has shown that available analytical models do not accurately predict wellbore storage duration and pressure behavior. Moreover, extended wellbore storage pressure data may appear to behave in a way similar to radial flow as seen on the pressure derivative curve. This misinterpretation usually results in a negative skin and the creation of nearby boundaries (i.e. which results in smaller reservoirs) making high potential wells appear to be limited.

This paper will present empirical and practical field solutions to this problem. Well test, stimulation, and production field data supported by computer simulations from oil and gas wells in the Gulf of Mexico area will be presented. The data presented in this paper will demonstrate how the test design and interpretation will effect the overall reservoir and well management of the field.

P. 119
Prediction of Hysteresis Performance of Storage Reservoirs
Authors: Tek M.R. , Fegley E. , Mantia R.W.
Published: December 2007

Based on equations describing pressure-content performance of gas reservoirs subject to water drive, the paper presents a solution developed for prediction of hysteresis performance of storage fields. The method validated using field data form several storage reservoirs has been developed into a storage performance simulator with a number of applications of interest to the storage industry. Prognostic reservoir studies for detecting loss of storage gas due to migration or wellbore seepage, calculation of cumulative loss as a function of time, cycling of aquifers, and recoverability of cushion gas are among the applications presented.

P. 247
History Matching for Lauchstaedt Underground Gas Storage
Authors: Zakirov I. , Asti A. , Zakirov E. , Schweng K.
Published: December 2007

Underground gas storage Lauchstaedt (East Germany) is represented by fractured reservoir. For adequate representation of considered deposit, an idea of two-layered reservoir has been chosen. One layer was responsible for the system of fractures, whereas another one corresponded to matrix blocks description. For this storage an automatic history matching procedure has been implemented that was based upon optimal control theory approach. Objective function to be minimized included the sum of least square mismatches of observed and calculated well's reservoir pressures. A conjugate gradient method was implemented to minimize given objective function. Applied history matching algorithm implied solution of forward and adjoint boundary value problems. A set of control parameters contained porosity and permeability of fractures and matrix blocks.

The problem of reservoir petrophysical properties estimation was investigated in 3D statement. Developed history matching algorithm turned out to be very efficient. A very good fit of observed and calculated well's grid block pressures has been reached after 8 iterations of gradient search procedure, nevertheless 10 control parameters were introduced. The most sensitive parameter happened to be porosity. It resulted in initial gas in place overestimation by 15% comparing with registered one.

It was also obtained a good match of observed and calculated pressures after manual history matching procedure for reservoir described as dual porosity layer. Only two matching parameters have been introduced in this case, namely

P. 263
Gas Management Models for Optimization of Elk Hills Gas Strategies
Authors: Yu J.P. , Ezekwe N. , Barua S.
Published: December 2007

This paper was prepared for presentation at the 1998 SPE Gas Technology Symposium held in Calgary, Aberta, Canada, 15-18 March 1998.
Determination of the Drilling Cost and Well Maintenance System in Perforacion y Mantenimiento de Pozos PPMP
Authors: Zamora Carlos Rasso , Romero Salvador Najera
Published: December 2007

PETROLEOS MEXICANOS and specifically PEMEX EXPLORACION y PRODUCCION has restructured the former regions around the oil fields called "assets", and this sector has focused on units of businesses, and the area of Drilling and Well Maintenance became a state-owned company which gives those services by changing its traditional technical focus to one emphasizing the technical-financial evaluation of its operations.

The present work describes the efforts to have a "Drilling Cost and Well Maintenance System", which allows transparence in the financial evaluation of the operations of the new state-owned company. The former institutional systems of PEMEX EXPLORACION y PRODUCCION used to total the information. The above way made the availability of its own financial statements difficult for the new organization to realize.

The definition of the financial structure of a new organization needs the setting of the methodology, inscriptions and the necessary concepts so that information can be reliable, useful and timely. One of these elements is the risk analysis, which has become an integral part of the decision maker in the oil industry as to know the economical feasibility of the projects. Therefore, the model of risk analysis used is shown in this work, including the "Monte Carlo" simulation with data of regional costs of the Operative Northeast Unit, statistical methods, analytic models, optimization, decision trees, sensitivity analysis and influence diagrams so that costs and required times for drilling a well can be forecast.

In a word, it has been possible to establish the "Drilling Cost and Well Maintenance System of PPMP" as a primary support of the financial structure of the new state-owned company. This will help PPMP to obtain its own financial statements and, of course, its physical-financial evaluation.

P. 453
Air Injection Technique (LTO Process) for IOR from Light Oil Reservoirs: Oxidation
Authors: Greaves M. , Ren S.R. , Rathbone R.R.
Published: December 2007

The feasibility of air injection into deep light oil reservoirs in the North Sea and elsewhere has been investigated. The low temperature oxidation (LTO) process removes oxygen in the injected air, to produce displacement gas (mainly nitrogen) in the reservoir in order to achieve incremental IOR. Reaction and displacement studies on four light oils have been carried out at reservoir conditions. This has involved the high pressure oxidation tube facility at Bath University as well as a small high pressure isothermal reactor.

This paper presents preliminary results on the reactivity of the oils studied in terms of oxygen consumption rate at reservoir temperature, and the oil recovery under low rate air injection.

P. 479
Effect of Coiled Tubing Initial Configuration on Buckling Behavior in a Hole of Constant Curvature
Authors: Weiyoung Qiu , Miska Stefan , Volk Leonard
Published: December 2007

In practical coiled tubing drilling and completion operations minor curvature always exists in coiled tubing (CT). The authors previously published that CT initial configuration results in the momentous reduction of the axial compression force required to produce helical configuration in a deviated well. In this paper the authors emphasize the effect of CT initial configuration on buckling/bending behavior in a hole of constant curvature. By utilizing the conservation of energy and the principle of virtual work, new equations are derived to predict the maximum permissible axial compression force to maintain a stable sinusoidal configuration and the axial compression force required to produce a helical configuration in a hole of constant curvature. These new equations reduce to those previously published when CT is not initially buckled. Practical examples are granted to demonstrate the effect of the initial amplitude on both sinusoidal and helical buckling behavior of CT in curved wells. The results indicate that the radius of curvature of a borehole is a governing parameter to influence CT buckling/bending behavior in a curved well. The effect of CT initial configuration on sinusoidal configuration can be neglected, whereas the effect of CT initial configuration on helical configuration is substantial. The results will help field engineer to understand CT buckling behaviors better, and consequently, to select proper CT to avoid the occurrence of lockup and to improve the prediction of the axial force transmission in horizontal and extended reach drilling. All equations manifested here can also be employed to conventional rotary drilling, slime hole drilling and tubular design.

P. 51
Electric Coiled Tubing Drilling - The First Steps Toward a Smart CT Drilling System
Authors: Head P.F. , Hanson T.J. , Yuratich M. , Turner D.R.
Published: December 2007

This paper describes a joint industry project to develop an electrically powered bottom hole assembly for use in coiled tubing drilling (CTD) applications.

Phase I of the project, recently completed in Aberdeen, produced a highly successful prototype assembly that recorded over 190 hours of drilling time without failure. Whilst the prototype was made almost entirely from existing technology, the success of the test has generated confidence to develop a more fit for purpose' motor.

A system overview explains the concept behind, and the advantages of, electric coiled tubing drilling (ECTD). The bottom hole assembly is described in detail, along with various surface components and the electrical power transmission system.

The testing program and operational procedures are outlined, together with some of the key results. The development plan for the technology is reviewed to highlight the ultimate goal of producing a smart' drilling system. It is envisaged that, based upon feedback from near-bit sensors, such a system would be able to automatically adjust certain parameters to optimize drilling performance.

The paper concludes that electric coiled tubing is a feasible and practical alternative to conventional CTD, although there are certain technological barriers that must be overcome.

P. 61
Development Update of an MWD Directional Drilling Package for 2-3/4" Openhole: Tiny Tools
Authors: Blount C.G. , Gantt L.L. , Hearn D.D. , Mooney M.B. , Smith B.E. , Quinn D. , Larson E.B.
Published: December 2007

This paper documents the development and first applications of ultra-slim diameter mud-pulse-telemetry directional drilling tools for applications through 3-1/2" production tubing.

The highly successful Coiled Tubing Drilling (CTD) program at Prudhoe Bay has concentrated on equipment required to re-enter 4-1/2" and larger tubing' sizes. Typical CTD re-entry operations have sidetracked existing wells at a cost 25% to 75% of past conventional rotary operations. However, there are a significant number of wells at Prudhoc Bay, other North Slope fields, and worldwide that have been completed using 3-1/2" tubing. The development of smaller diameter directional tools allow through-tubing CTD re-entry techniques to be extended to a dramatically larger number of existing wells and also allows options for zonal isolation using small ID intermediate strings in larger tubing sizes.

Purpose built equipment needed to allow directional drilling through typical 3-1/2" tubulars has now been developed and utilized to drill the world's first directionally steered 2.75" bore holes at Prudhoe Bay. This newly developed equipment was used with CT to directionally extend the horizontal section below existing- 3 1/2" tubing strings. Economics of the first 6 wells would indicate a level of performance and cost effectiveness consistent with the larger CTD equipment.

This paper details the design criteria and covers the operational implementation of the 2-3/8" OD directional drilling assembly, referred to as "Tiny Tools" by those developing the technology. Window milling and bicenter bit performance and results will also be discussed. The problems and solutions of tool development, along with the execution of the first CTD jobs through 3" tubulars are also addressed.

P. 79
CT ESP for Yme, Converting the Yme Field Offshore Norway from a Conventional Rig-Operated Field to CT-Operated for Workover and Drilling Applications
Authors: Baklid Allan , Apeland Odd Johan , Teigen Alv Sigve
Published: December 2007

Conventional tubing deployed ESP was initially chosen as the artificial lift method for the Yme field offshore Norway. Two years of operational experience proved that the method chosen did not meet the original design criteria with regards to preventing fluid loss to the formation during workovers and access to the reservoir with wireline/coiled tubing. In addition, the average ESP lifetime was initially well below the target runlife.

The current ESP-completion design is described. Main operational problems experienced during two years of operation is highlighted. The revised field requirements and a re-evaluation of artificial lift methods proved the need for a change in completion philosophy. Coiled Tubing Deployed ESPs (CT-ESP) utilizing an internally installed power cable became the preferred method.

The value of installing CT-ESP in a live well is discussed. System design for true underbalanced CT-ESP installation is described. Well control and barrier philosophy during installation, production and workover mode is also assessed.
Coiled Tubing Velocity Strings - Expanding the Cases
Authors: Martinez Alec , Martinez John
Published: December 2007

Coiled tubing is a preferred remedial method of extending the flowing life for gas wells. but selection of a size that will accomplish the task of removing bottomhole liquids is not simple. The difficult, in predicting results that guide coiled tubing selectivity is partly caused by the changing gas to liquid flow rates in the wellbore as the accumulated liquid discharges. This paper provides a guide to the prediction making process, with emphasis on the modeling methods which are needed.

The variables that serve as indicators of the viability of each tubing size are velocity and liquid holdup. The values that should be used for criteria were reviewed in SPE 30197, Modeling Coiled Tubing Velocity Strings for Gas Wells. Those criteria are used with the prediction procedure to expand the selection process to cover a wider range of coiled tubing sizes and gas-liquid flow rates.

P. 111
The Benefits of Real-Time Coiled Tubing Diameter Measurements
Authors: Quigley M.S. , Stone L.R.
Published: December 2007

Coiled tubing (CT) becomes oval during normal use due to plastic bending on the reel. This ovality significantly decreases the collapse resistance of the CT, and, in extreme cases, can restrict the passage of the CT through the surface equipment. During pumping operations, the internal pressure can cause the CT to balloon as it plastically deforms on the reel and guide arch. The increase in the CT diameter causes a corresponding decrease in the wall thickness. Both effects substantially weaken the CT's collapse resistance and decrease its working life. Some CT software can estimate the ballooning and its effects on collapse and working life. However, no models exist for predicting the ever-changing ovality of CT.

A newly-developed tool can automatically measure the diameter and ovality of the tubing during actual CT operations. This real-time information is available to the CT operator for monitoring the status of the tubing and determining its suitability for continued use. Communications ports in the electronics module can feed the diameter data to a computer or data acquisition system for permanent storage or input to other monitoring software.

P. 171
Lossy Transmission Line Model of Hydrofractured Well Dynamics
Authors: Patzek Tadeusz W. , De Asoke
Published: December 2007

The real-time detection of hydrofracture growth is crucial to the successful operation of water, CO2 or steam injection wells in low-permeability reservoirs and to the prevention of subsidence and well failure. In this paper, we describe propagation of very low frequency (1-10 to 100 Hz) Stoneley waves in a fluid-filled wellbore and their interactions with the fundamental wave mode in a vertical hydrofracture. We demonstrate that Stoneley-wave loses energy to the fracture and that energy transfer from the wellbore to the fracture opening is most efficient in soft rocks. We conclude that placing the wave source and receivers beneath the injection packer provides the most efficient means of hydrofracture monitoring. We then present the lossy transmission line model of wellbore and fracture for the detection and characterization of fracture state and volume. We show that this model captures the wellbore and fracture geometry, the physical properties of injected fluid and the wellbore-fracture system dynamics. The model is then compared with experimentally measured well responses. The simulated responses are in good agreement with published experimental data from several water injection wells with depths ranging from 1000 ft to 9000 ft. Hence, we conclude that the transmission line model of water injectors adequately captures wellbore and fracture dynamics. Using an extensive data set for the South Belridge Diatomite waterfloods, we demonstrate that even for very shallow wells the fracture size and state can be adequately recognized at wellhead. Finally, we simulate the effects of hydrofracture extension on the transient response to a pulse signal generated at wellhead. We show that hydrofracture extensions can indeed be detected by monitoring the wellhead pressure at sufficiently low frequencies.
Evaluation of Geochemical Approaches to Heavy Oil Viscosity Mapping in San Joaquin Valley, California
Authors: Henshaw P.C. , Carlson R.M.K. , Pena M.M. , Boduszynski M.M. , Rechsteiner C.E. , Shafizadeh A.S.G.
Published: December 2007

Areal and vertical distributions of petroleum viscosities within heavy oil reservoirs are important in designing well completions, optimizing field development and planning thermal and other recovery operations. Viscosities of oils in closely-spaced reservoir zones in heavy oil fields can vary substantially. Unfortunately, oil samples are often unavailable or too small for conventional laboratory viscosity measurements. In such cases, correlations between heavy oil viscosity and geochemical, chemical and physical parameters can be valuable for estimating working viscosities. Various geochemical-viscosity correlations were evaluated using a suite of heavy crude oils (API gravities < 150) from fields in the San Joaquin Valley, California. Whole, dewatered, crude oils where studied. Kinematic viscosities were measured at multiple temperatures. Elemental, organic acid, pour point and gravity analyses were completed, followed by compound class separations and gas chromatographic analyses. Statistical methods were used to assess correlations of various parameters with viscosity. Results were compared with correlations reported in the literature and evaluated in terms of linkage to models of field-wide degradation processes believed to account for formation of the heavy oils, with the goal of assessing these predictive models for viscosity variations with applications to viscosity mapping.
A Study of Steam-Water Relative Permeability
Authors: Satik Cengiz
Published: December 2007

In this paper we report on experimental efforts to measure accurate steam-water relative permeability functions under steady-state and non-adiabatic conditions. We conducted a steady-state flow experiment in which a mixture of superheated steam and liquid hot water was injected at varying fractions into a Berea sandstone core sample and steam-water relative permeability was calculated. These experimental results show that the relative permeabilities for both steam and water phases in porous media vary with saturation in a curvilinear fashion. The saturations in this experiment were measured by using an X-ray computer tomography scanner. Pressure gradients were obtained from accurate measurements over regions with flat saturation profiles. These two issues constitute a major improvement in the experimental method compared to those used in the past. Numerical simulations were also carried out for the simultaneous injection of steam and water into a core by using STARS simulator. At steady- state conditions, the effects of steam quality, total injection rate and the type of relative permeability curve on saturation profiles were investigated. To extend the results to general steam-water flows in porous media, similar experiments will be conducted at higher temperatures and with rock samples having different permeability and wettability characteristics.
Foam Cementing Cyclic-Steam, Producing Wells: Cymric Field Case Study
Authors: Miller Larry S. , Frank William E.
Published: December 2007

Primary cementing of production casing for cyclic-steam wells in shallow, weak formations presents several challenges. This paper discusses the application and optimization of foamed cement that was done to solve the primary cementing problems in an ongoing developmental drilling project in a portion of the Cymric field in California's San Joaquin Valley. Improvements in cement placement and reductions in well damage from operational stresses are shown.
A Reservoir Management Model for 26R Reservoir, Elk Hills Oil Field, California
Authors: Echols D.P. , Ezakwe Nnaemeka
Published: December 2007

The 26R Reservoir is a massive sandstone Stevens reservoir in Elk Hills Oilfield. Crestal gas injection was initiated in the reservoir for pressure maintenance immediately after open-up in 1976. Since 1988 the reservoir has been developed extensively with horizontal wells. To date, there are twenty-two horizontal wells completed in the reservoir which accounts for more than 70% of total oil production. A reservoir flow model, referred to as the 26R Reservoir Management Model, was developed with the aid of geostatistics to evaluate alternative management strategies such as full or partial pressure maintenance, termination of gas injection, or drilling more horizontal wells. Prediction results indicate that full pressure maintenance will recover more oil but severely reduce the volume of gas available for sales. They also show that more horizontal wells could be drilled especially in the western half of the reservoir.
Disposal of Crude Contaminated Soil Through Slurry Fracture Injection at the West Coyote Field in California
Authors: Sipple-Srinivasan M.M. , Bruno M.S. , Hejl K.A. , Danyluk P.G. , Olmstead S.E.
Published: December 2007

The first permitted operation in California for disposal by deep injection of crude contaminated surface soils was completed this summer at the West Coyote Field in La Habra, California. Approximately 14,000 barrels of waste material was disposed of from this abandoned oilfield site. The material included crude contaminated surface soil derived primarily from production well cellars, and dried and liquid drilling muds. Waste streams included screened and unscreened soil. The solid waste material was loaded into a hopper and conveyance system, then transferred to a shaker unit. Some liquid wastes were also processed through tubing connected directly from vacuum trucks into the shaker unit. Approximately 50,000 bbls of a slurry mixture of waste material plus fresh water was injected over a three week period into a high porosity (30%), high permeability (500 md) depleted oil sand at a depth of approximately 4100 ft. Average daily injection volumes were on the order of 4,300 bbls/day of slurry, with solids concentration in the slurry as high as 35% by volume.

The permitting phase of this pilot project extended over 18 months and required modification of State regulatory guidelines to accommodate injection of solid materials above parting pressure of the target formation, as well as disposal of surface soils not previously included in the classification of Class II fluids. After demonstration of an acceptable monitoring and analysis strategy designed to ensure containment of the waste material within the target formation, the California Division of Oil and Gas and Geothermal Resources (DOGGR) approved the permit application in early 1997. Final approval from the Regional Water Quality Control Board followed. Close cooperation between DOGGR, the operating company, and the injection service company paved the way for the success of this disposal operation in an environmentally sound and permanent manner with minimal impact to surface land use, and reduced long-term liability to the operator.
Combustion Front and Burned Zone Growth in Successful California ISC Projects
Authors: Garthoffner Egon H.
Published: December 2007

This paper examines the concepts of combustion front, shape, orientation and propagation. It supports the concept of a horizontal combustion surface and a burned zone that has the shape and position similar to that of a conventional gas cap.

Clear direct as well as indirect evidence is presented in support of the claim that combustion surfaces develop and propagate horizontally. The direct evidence comes from the results of coring through the burned interval and from temperature profiles at observation wells and replacement wells. Indirect evidence comes from the analysis of produced gas and gas production rates. We also propose that convection currents play an important role in the growth of horizontal combustion surfaces and their propagation down through the reservoir sands.

The development of horizontal combustion surfaces as a result of air injection is a natural occurrence just as the development of a gas cap is to natural gas injection. In all, it is a highly beneficial activity. It improves volumetric sweep efficiency and allows even irregular well spacing and irregular patterns to be exploited. It also makes it possible to apply ISC to small oil pools that are not suitable for pattern development and to thin reservoirs.
Environmentally Sensitive Flares: No Smoke, Odor or Noise; and No Visible Flame
Authors: Straitz John F.
Published: December 2007

Onshore and offshore, flares are essential safety systems for energy exploration, production, transportation and storage, including ship-board flares on floating production, storage and off-loading (FPSO) vessels. Despite extremely wide variations in the flow of volatile, carcinogenic waste gases or other dangerous offgases, and regardless of the worst weather conditions, including hurricane or typhoon-force winds up to 400 km/hr (250 mph), flares must work right, each and every time, or the consequences can be catastrophic.

The two most important considerations in flaring waste gases or offgases must always be safety and reliability. Protection of the regional and global environment by dependable and complete in-cineration of waste streams is another very important requirement. Burners of various configurations are the heart of all flare systems. Instrumentation and control systems are the nervous system and the brains.

Low-profile enclosed flares and in-ground earthen enclosed flares offer many advantages in comparison to elevated (open-burner) flares. With state-of-art enclosed flares, sometimes called "thermal oxidizer flares", energy recovery from flared streams of gases, as well as liquids and slurries, is possible.
Investigation and Remediation of Hydrocarbon Contamination above Permafrost
Authors: Ratliff M. D.
Published: December 2007

The paper discusses a recent remediation project at an oilfield service facility in Deadhorse, Alaska, approximately 300 miles north of the Arctic Circle. The construction of the gravel pad on top of the tundra and the unique environment of performing remediation above permafrost presented significant challenges. This paper will define the problems caused by the northern location ofthe site and the unique movement ofhydrocarbons on the permafrost, and explain how those problems were overcome. The issue of hydrocarbon contamination and its possible remediation is paramount to the continued exploration and production in sensitive arctic regions, such as current operations in northern Russia. Other examples of such regions, which are usually pristine environments, are the Arctic National Wildlife Refuge and the Northwest Territories of Canada.
How clean is clean - Recommended Framework for Rendering an Offshore Installation Clean
Authors: Aabel J. P. , Tibble S. , Helland B.
Published: December 2007

There is a growing concern regarding the fate of oil and gas facilities for which abandonment is programmed as a result of declining production. Different abandonment options have been proposed for consideration in recent years, varying from total removal of all elements of the installations to toppling in place or abandonment in-situ. Any abandonment option that involves abandonment in-situ or temporary or permanent placement of one or several elements of an installation on the seabed could be seen as a potential source of pollution. The probability of pollution depends on the type of installation, procedures for cleaning the platform and the nature and sensitivity of the receiving environment.

This paper presents the objectives and recommended practice for the preparatory works required to render a cold state multi-function steel jacket installation clean. The basis for this framework procedure was an assessment of the technical limitations and relevant legislative requirements and constraints and the findings of a preliminary qualitative risk assessment of the potential environmental implications of the entry into the North Sea offshore marine environment of the residual materials inventory.

An Appendix summarizes the recommended framework procedure developed that was based in part of the following recommendations proposed from the findings of the preliminary risk assessment:

all components containing PCBs should be removed; all components containing halons/freons should be removed; persistent synthetic substances should be removed where practical; production chemicals should be taken onshore for disposal; topside tanks and pipework should be cleaned as far as practical to removed residual sediments containing heavy metals and hydrocarbons; and components/equipment containing radionuclides should be removed.
Environmental Evaluation Systems for Well Drilling and Completion Chemicals -The Present Situation and Future Views
Authors: Berg Erik , Romijn Henk , Wolting Bert
Published: December 2007

This paper describes how chemical hazard and risk assessment systems are being used in North Sea countries. Despite efforts to establish a harmonised chemical hazard and risk system, many countries have developed their own systems. For this reason, three major service companies have been working together to evaluate the CHARM III model (Chemical Hazard Assessment and Risk Management)1,2 and the accepted chemical hazard and risk assessment systems.

Initially implemented by the Oslo Paris Commission (OSPAR), the European regulatory body for offshore environmental issues, CHARM III was a significant step towards developing a simple model that generated consistent hazard/risk evaluation results. During the harmonisation process, the North Sea countries also made attempts to develop a harmonised mandatory control system.3 Currently, four North Sea countries still rely on their own chemical evaluation systems.

The three service companies have used the CHARM III model to perform chemical hazard evaluations on a representative range of cementing, completion, workover and spacer chemicals. The same chemicals were also evaluated with the different pre-screen systems used by the North Sea countries (Tables 1 and 2).
Crude Oil Recovery in Oiler Residual Pits in Boscan Field
Authors: Zabala A. , de Jongh A. , Padron A.
Published: December 2007

The oil industry activities generate a great amount of wastes resulting from oil spills, tanks cleaning and maintenance, drilling, etc., which are dispossed in pits, creating a negative environmental impact. The recoverable crude oil from these pits is estimated to be about 2 MMBBLS. This makes its recoverable economically attractive.

The recovery process is based on fundamental operations like Dilution, Formulation of oil/water Dispersions using Sodium Silicate as natural surfactant active agent present in the oil and Static Dehydration by Heating and Chemical Demulsification Treatment.

In this work, the different phases of the study, beginning from the results obtained on laboratory scale and subsequently industrial application on a pit in the Boscan Field are presented. The oil recovered in this way was later reincorporated into the production line.
Contrasting HSE Approaches by an Oil Company to Concurrent Seismic Operations in a New Country
Authors: Thonger Rod C
Published: December 2007

This paper describes the contrasting approaches taken by Enterprise Oil in their two new Greek licenses during 1997. Seismic operations were set up for the northern, mountainous, heli-supported dynamite project with a major international contractor. The southern prospect involved vibroseis in mostly flat countryside with the purely domestic geophysical division of the state oil company.

Co-operation between client and contractor was given the highest priority, and expert assistance provided where needed. This included safety management training and the provision of helicopter and mountaineering experience in addition to the normal schedule of training. The inclusion of sub-contractors was a key necessity.

The objective was to ensure that both contractors were as ready as reasonably practicable to start work before going to the field and in the early stages of production. A major problem in starting seismic crews has frequently been the short lead time between award of the work and the start of operations. HSE matters are often left behind in the rush to the field so the paper offers a solution to this problem which should satisfy both the client and the contractor.

This paper will show how each crew was approached from the Client point of view on HSE matters, give field results, give a comparison of additional HSE investment up front and actual production against budgeted production under usual start-up methods. A key point will be to show that by getting the management and the work procedures right at the beginning in order to control the HSE aspects, there were time and financial gains made over the whole project.
HSE Management of Geophysical Operations: The Client's Role
Authors: Dolezal Alan L.
Published: December 2007

Over the last ten years, most exploration and production companies have discontinued the use of company seismic crews, and now these companies depend on contractors to acquire their geophysical data. The increased use of contractors has resulted in a shift of the majority of the effort to manage risk of incidents from the company to the contractor. However, there are significant benefits for companies, clients, to work with their contractors in preparing a sound Health, Safety and Environmental (HSE) plan for each geophysical project.

This paper describes Exxon Exploration Company's approach for working with contractors to lower the risk of HSE incidents during the acquisition of geophysical data. Exxon uses a structured process that consists of written guidelines and checklists to ensure that key elements of the contractor's HSE plan are in place before the project begins and functioning during the project. The key action items or activities required by the structured process are described for the four main project phases: Pre-Bid, Pre-Survey, Survey and Post-Survey.
Highly Inhibitive, Low-Salinity Glycol Water-Base Drilling Fluid for Shale Drilling In Environmentally Sensitive Locations
Authors: Brady M. E. , Craster B. , Getliff J. M. , Reid P. I.
Published: December 2007

Water-base drilling fluids containing glycol additives have become established for cost-effective drilling of many reactive shale formations. Existing fluids function most effectively when the glycol is used in conjunction with moderate to high levels of salt; potassium chloride is most commonly used, although this can sometimes be replaced by sodium or calcium chloride or by more expensive acetate or formate salts.

In many onshore locations, discharge of saline drilling wastes poses environmental problems because of contamination of groundwater and soil which may make the water unsuitable for drinking or irrigation and agriculture. In these situations, either expensive pollution control measures or low-salinity drilling fluids are required. Unfortunately, the glycols in common use for shale control do not function well in salt-free or low-salt fluids, so their benefits cannot be fully exploited in these environmentally sensitive areas.

This paper discusses the technical performance and environmental benefits of a new class of glycol inhibitors, specifically designed to provide high levels of shale inhibition in freshwater and low-salinity water-base drilling fluids. Waste disposal implications are considered and inhibitive properties are compared with other currently available fluids.
Aquila Oil Field: Safety and Reliability in the Development of Deepwater Field
Authors: Rizzi W. , Priotti W.
Published: December 2007

The development of marginal fields in deepwater and hostile environmental conditions represents a technological challenge which to be winning, must conciliate competitive with safety and environmental protection. For this reason, since the beginning of Aquila Project, Safety Dept. was called to join the Project Task Force internally established, to sum up resources with experiences in the main technological areas. These specialists have not been permanently part of the Task Force but they were the reference individuals throughout the project life. From this point of view, Aquila oil field could be considered as a model: since from the early engineering phase, safety analysis, as HAZID and HAZOP and other studies have been done and the results were implemented into the detailed engineering. The risk assessment considered the overall development system as well as the certification; from downhole completion up to the offloading operation, equipment, operations and procedures have been considered.

This paper highlights the most significant studies and recommendations issued in the HAZOP works with the aim to increase the safety conditions during installation and production phase.

In particular the following were considered:

Dropped Object Study: to establish the probability of damage to the subsea equipment resulting from objects potentially dropped from surface; Use of well fuel gas (sour) in the engine room: to minimise the potential presence of sour gas in the vicinity of the Living Quarter especially in case of leakage from pipes carrying gas to Boiler, or in case of any gas emergency; Probabilistic analysis of incidental sequences concerning the leakage of production pipes in the turret area.
Safety FPSO Consideration for Girassol Deepwater Development Project
Authors: Tonda Henri
Published: December 2007

For deep water field developments as Girassol in Angola, a Floating Production System and Offloading (FPSO) unit provides a good economical and production facility. However is such FPSO as safe as a standard fixed unit ?.

Due to its concept, a FPSO has three main functions: oil processing, floating storage and offshore terminal. By consequence, the FPSO main hazards are, at least, the hazards related to these functions when they are implemented onto different supports. In addition, the concentration of these hazards onto the same support leads to increase the risk on both the frequency and the consequence sides, due to the possible functions’ interactions.

The paper presents the risk assessment performed at the Girassol pre-project phase. Due to the little field experiences of FPSO's, the study was mainly based on the adaptation of historical data relating to fixed offshore platforms, trading tankers and ports.

It appears that the risk to loose a FPSO based on a standard tanker without any dedicated design precautions is roughly estimated to be 28 times higher than the risk of total loss of a North sea platform.

The study was formally integrated into the conceptual activities of FPSO. The practical issues relating to the concept selection is presented as well as the assessment of the possible risk reducing
Operational Lessons from the UKCS Hydrocarbon Leaks Database
Authors: Bonn Robert J.C.
Published: December 2007

Since 1992, Operators in the UK sector of the North Sea have been reporting all hydro-carbon leaks to the Health and Safety Executive (HSE). The resulting data-base is the most detailed of its kind in the World. The HSE and the Operators Association (UKOOA) are to produce analyses of the data for use in Quantified Risk Assessments and for bench-marking safety performance.

There are other lessons which this valuable data can teach us. This paper will identify areas where improvements to design and operational practices can have a significant benefit, not just in terms of the number of releases, but also in terms of risk.

This paper will focus on the causes of high risk incidents, with the causes grouped into categories of: Design, Equipment, Operations and Procedural failures. The analysis has revealed lessons which can be used to make significant reductions in the frequency of releases for new and existing sites. This in turn will, improve safety performance and reduce environmental impact of E&P operations around the World.
The Adoption of Technical Safety Assessment Tools in Oil and Gas Development Projects
Authors: Wright G. J. , Newton M. A.
Published: December 2007

BHP Petroleum operates 3 Floating Production and Storage Offloading Units (FPSOs) and two onshore plants in Australia, offshore facilities in Western Europe with a number of global projects in various stages of development that will take the company into the year 2000 and beyond. In 1995, the company embarked on a safety improvement programme, to integrate technical safety assessment within the operating and design processes. This demanded the development of comprehensive and detailed safety study plans for all new projects, and the preparation of safety cases for our existing facilities. The plans set out the technical safety related work required during the course of a project's life time, and are primarily used to programme the development of safety cases. The objective of this strategy is to ensure that the safety study work keeps pace with, and has an effective input to the design, and ultimately, that the operating safety risk levels are as low as is reasonably practicable, that is ALARP. This paper includes a description of the development of offshore safety cases and their application, for example, to the effective targeting of competency based training efforts, and risk based strategies for maintenance, inspection, and testing programmes for operating facilities. The adoption and use of standardised QRA rule sets and assumptions is also discussed together with the processes used to determine the tolerability of a facility's risk levels. And finally the use of benchmarking, audits, and reviews for sustained improvement in safety performance is examined.
New Strategy of Controlling Risks in Development of Oil & Gas Fields with Hydrogen Sulfide
Authors: Koutsyn P. V. , Gendel G. L.
Published: December 2007

As a result of analysis of long standing experimental investigations, objective laws were discovered and mathematic models of technogenic risks were formed. The author investigated the risks associated with possible emergency releases of H2S-containing vapours of gases when developing oil & gas fields.

Criteria were substantiated and evaluation methods were created for the level of dangerous H2S intoxication with due regard for the time of its impact to a person and dynamics of air contamination level in conditions of real emergency situations. Efficiency of already known and new proposed measures was evaluated theoretically and experimentally. Such measures envisage "passive" protection of people and environment as well as active influence to an emergency release of gas.

New strategy of technogenic risk control was proposed. It is applicable to typical targets of oil & gas industry. It is based on rational organizational measures, computer programs and other technical means, technologies and devices for operative prevention, protection and liquidation of emergency.

Unlike earlier applied emergency programs, new technologies of active impact to the source of emergency gas release and to the spreading clowd of toxic gas-air mixture were recommended for practical usage as the most efficient and rational ones. Results of practical tests of proposed methods at the largest oil & gas producing complexes in Russia have been considered in this paper. The achieved efficiency allows to recommend the proposed methods for practical usage at chemically dangerous targets of various industries in order to provide safety of people and to protect environment against emergency contamination of air.