bluuebunny/crossref_metadata_2025 huggingface dataset:
Slim-Hole, High-Volume, PC Pump Development for 140 mm Cased Well Applications
Authors: Chachula R. C. , Anderson D. G.
Published: December 2007

The slim hole high volume progressive cavity pump project was initiated to demonstrate that such an artificial lift technology could work successfully in viscous sand-cut crude slant well pad type field applications. The basic concept was to develop an innovative cost effective PC pumping system for reduced diameter longstring cased (140 mm or 5,50″) wells that has the capability of pumping-off projected target rates at reduced RPM's. Ultimately, a reduction in capital and operating expenditures is achievable for existing and future developments through the improved technology.

The successful performance of the prototype installations prompted the design and drilling of four pad sites comprised of two, 16 well and two, 8 well pad configurations. The authors concluded that successful pump performance and efficiencies in pumping-off 12° API sand laden crude would be achievable at reduced speeds within 35–45° reduced diameter slant wells. The reduced stator OD combined with flush tubing directly above the PC pump prevented the occurrence of "sand-ins" between the tubing-annular area, thereby reduced the frequency of servicing wells.

The ability to reduce producing problems associated with initial high sand volumes have focused current field studies on developing correlations between anticipated sand cuts and varying fluid viscosity to surface torque and pumping speed required. PC pump developments are focused on improving pump life through improved elastomers and new pump designs. Knowledge gained from these studies will lead to successful slim hole performance and point the way to future innovative technical developments in the areas of rodless pumping systems, downhole oil/water separation and modified power transmission components.

This paper describes the evolution of the progressive cavity pump system in the development of the Mannville Formations in the Wainwright-Frog Lake fields. Modifications made to the equipment design and techniques to optimize pumping operations is discussed.
Eliminating Sucker Rod Couplings Can Reduce Progressing Cavity Pump Operating Costs
Authors: Wiltse D. J. , Weir B. A.
Published: December 2007

It is common knowledge that some of the obstacles that must be overcome to successfully operate Progressing Cavity Pumping (PCP) Systems are attributed to conventional sucker rod couplings and the upset area around them.

This paper addresses how the use of continuous sucker rod in PCP Systems can dramatically reduce the overall operating costs in high viscosity, heavy oil lifting applications, as well as, high water cut, high volume lifting applications.

Eliminating the conventional sucker rod couplings, and therefore the constricting annulus effect, will alter the pump requirement by decreasing the differential pressure the pump must overcome. Thereby decreasing the horsepower requirement and ultimately decreasing the power consumption.

In watering out pay zones, completed with 73 mm (2-7/8″) tubing, a 25.4 mm (1″) sucker rod string may be required to accommodate the extra torque associated with lifting higher volumes of fluid. 25.4 mm (1″) continuous sucker rod can contribute to additional cost savings by providing the additional torque carrying capacity without increasing the tubing size.

Through the use of independent software modeling a comparison of conventional sucker rods versus continuous sucker rod in PCP Systems will be presented to illustrate how operating cost reductions may be realized through the elimination of the conventional sucker rod couplings.
Numerical Study of the SAGD Process in the Burnt Lake Oil Sands Lease
Authors: Kisman K. E. , Yeung K. C.
Published: December 2007

A numerical study was conducted to predict recovery performance for the steam-assisted gravity-drainage (SAGD) process in the Burnt Lake oil sands lease. A geological and petrophysical description of the lease and a base case numerical model were prepared. Experience gained at the very successful Alberta Department of Energy Underground Test Facility (UTF) SAGD pilot was utilized in the numerical modelling.

The base case predicted favorable performance for a 1000 m long horizontal well pair, with a calendar day oil rate over 15 years of 70.1 m3/d, and an oil-steam ratio of 0.34. Optimisation of SAGD operations and factors such as spacing between well pairs will enhance the predicted performance.

Sensitivity studies showed that the SAGD process at the Burnt Lake site is expected to be robust, with a low to moderate sensitivity of recovery performance to reservoir properties within the range of uncertainty of these properties. The reservoir properties investigated include permeability, relative permeability, wettability changes, oil viscosity, thermal conductivity, flow barriers, and solution gas effects. Other factors investigated include operating pressure and placement of the production well. The only factor with a large effect on overall performance was placing the production well in a low permeability zone.
Coalinga Horizontal Well Applications: Present and Future
Authors: Huff Brian
Published: December 2007

The Etchegoin reservoir in the Coalinga Field contains over 40MMB of 10–11° API oil-in-place. The reservoir dips at about 14–20°. Following an infill program in 1991, remapping of the reservoir showed significant remaining oil in the downdip area.

Two downdip horizontal wells were planned and drilled in the Basal sand member. Together the wells develop a 25 acre area containing 1.1 MMBO. Production forecasts were generated using a simple analytical model. The model can predict initial production rates but is not adequate for gravity drainage situations. The paper discusses a number of special well design considerations.

Post-soak well performance was promising but showed the need for additional reservoir heat. Slim-hole injectors were added updip and near the horizontal wellbore. Today the two wells add 500 BDO to Coalinga production. This represents 10% of Etchegoin total production.

The Coalinga Team continues to look for additional horizontal well opportunities. Additional potential includes: 1) a new development area with multiple stacked sands of varying continuity, 2) a hot portion of the reservoir where steam entry into vertical wells causes impairment, 3) more downdip extension potential, and 4) a new thin reservoir with limited extent that might be a candidate for multi-lateral well technology.
Study and Practice on Recovery by Steamflood in Heavy Oil Reservoir with Edge and Bottom Water
Authors: Yuanqin Yao , Yingjie Zhou , Xianmin Li
Published: December 2007

This article provides an example of steamflood pilot which is a heavy oil reservoir with thick sandy formation and active edge and bottom water. It presents the cases of pilot emphatically such as performing steamflood conditions, opportunity, steamflood project, the characteristics of steamflood performance, some technical measures selected to improve steamflood effect and also furnishes a evaluation of developed results.
Cyclic Stimulation of Cold Lake Oil Sand With Supercritical Ethane
Authors: Lim G. B. , Kry R. P. , Harker B. C. , Jha Calgary K. N.
Published: December 2007

In a three dimensional scaled physical modeling experiment, Cold Lake oil sand was subjected to cyclic stimulation with supercritical ethane through a single horizontal injector/producer well located at the base of the reservoir. Hot ethane gas was injected into the bottom of the formation until the bottle hole pressure reached slightly above the ethane supercritical pressure of 4.9 MPa. Production of diluted bitumen followed the injection cycle through the same horizontal well until pressure in the reservoir was depleted slightly below 4 MPa. At that pressure liquid production rates were very low. During the experiment, temperature in the model varied considerably with the distance from the wellbore as well as with the number of stimulation cycles.

Supercritical ethane enhanced the cyclic solvent gas process by improving the early production rate. As well there was an increase of recovery of solvent in the blowdown at the end of the experiment. Both are important factors for the process economics.

Time animation of the temperature profile revealed that solvent gas preferentially invaded the region in close proximity to the production end of the horizontal well. The observation was consistent with the post test measurement of residual oil saturation in the model which showed that bitumen was preferentially depleted from that region. Evidently, full utilization of the horizontal well was not achieved in the experiment. Production enhancements would be expected if this technical deficiency could be overcome.
In-Situ Upgrading of Heavy Oils by Low-Temperature Oxidation in the Presence of Caustic Additives
Authors: Wiehert G. C. , Okazawa N. E. , Moore R. G. , Belgrave J. D. M.
Published: December 2007

The literature of the past thirty years shows that the low-temperature oxidation (LTO) of hydrocarbon liquids generally results in a more viscous end product. The In Situ Combustion Research Group at The University of Calgary has found, however, that upgrading can occur during LTO in the presence of caustic additives. Because it was believed that caustic inhibits oxidation reactions as evidenced by a reduction in or absence of coke formation, and allows the oil to upgrade by thermal cracking via a free radical mechanism, a systematic study was undertaken to investigate the effect of caustic on the LTO of heavy oil.

To date, nearly 200 LTO tests have been performed on Athabasca bitumen. These experiments were carried out by varying caustic concentrations, temperatures, oxygen partial pressures, total cell pressures, and run times. All effleunt gases were analyzed using gas chromatography, the pH of free water was measured, and hydrocarbon products underwent determination of coke and asphaltene contents, viscosity, and density. CHN and S analyses were carried out on the whole oil, and coke and asphaltene fractions.

Several instances of upgrading were observed. Optimum conditions occurred at lower caustic concentrations, lower temperatures, lower oxygen partial pressures, and longer run times. The amount of oxygen reacted appears to be the most critical parameter affecting the system. The presence of caustic apparently did not inhibit the oxidation reactions from taking place, but, rather, modified the process by impeding the asphaltene fraction from converting to coke.
Pressure-Volume-Temperature Correlations for Heavy and Extra Heavy Oils
Authors: De Ghetto Giambattista , Paone Francesco , Villa Marco
Published: December 2007

The paper evaluates the reliability of the most common empirical correlations used for determining reservoir fluid properties whenever laboratory PVT data are not available: bubblepoint pressure, solution GOR, bubblepoint OFVF, isothermal compressibility, dead-oil viscosity, gas-saturated oil viscosity and undersaturated oil viscosity,

The reliability has been evaluated against a set of about 65 heavy and extra-heavy oil samples. About 1200 measured data points have been collected and investigated. All measured data points are reported in the paper. For all the correlations, the following statistical parameters have been calculated: a) relative deviation between estimated and experimental values, b) average absolute percent error, c) standard deviation.

Oil samples have been divided in two different API gravity classes: extra-heavy oils for °API< 10, heavy oils for 10<°API< 22.3.

The best correlations for each class of API gravity have been evaluated for each oil-property.

The functional forms of the correlations that gave the best results for each oil property have been used for finding a better correlation with errors reduced, on average, by 10%. In particular, for extra-heavy oils, since no correlations are available in literature (except for viscosity), a special investigation has been performed and new equations are proposed.
A Mathematic Model of Electrical Heating in Hollow Pump Rod and Its Application
Authors: Cheng Y. M. , Guo C. Z. , Gong L.
Published: December 2007

For heavy oil production well, especially at the situation of cold production, it is essential to maintain enough flow energy of the fluid along the wellbore, hence, the temperature distribution in the wellbore at various conditions should be made certain so as to determine the reasonable production.way and equipments. At present, the most effective measure is to heat the oil using hollow pump rod with an electric cable inside.

In this paper, a mathematic model, which was successfully estabished to represent electrical heating with a cable in hollow pump rod, is described. It considers the heat transfer mechanisms of conduction, convection and radiation and the changes of physical properties and thermal properties of mixtures of oil and water. This model is practical and the calculation results can provide basis to design the production of heavy oil well, such as power supply capacity, depth of cable, production rate etc, can be determined and optimized. Its application in Jidong oilfield, which has indicated it is very effective, is also discussed.
Development and Operation of a New Insulated Concentric Coiled Tubing String For Continuous Steam Injection In Heavy Oil Production
Authors: Luft H. B. , PeiensKy P. J. , George G. E.
Published: December 2007

The design, testing, construction and installation of a prototype insulated concentric coiled tubing (ICCT), 1700m in length for continuous steam injection in a horizontal well, was recently completed. The concentric tubing consists of a 1-3/4" inner and 2-7/8" outer coiled tubing separated by loose-fill insulation and specially designed composite-construction centralizers. The ICCT R & D required the development of a new, low thermal conductivity centraliser, the design of thermal expansion joints utilizing advanced seal technology suitable for a high pressure and greater than normal steam temperature of 350C (662F) and the application of modem orbital welding processes for ICCT welded connections. The experimental steam injection process consists of continuous steam injection and oil production from the same well bore. Oil production commenced

January 9, 1995 and successful operation has been achieved to date.

This paper describes and presents the results of insulation heat loss and frictional resistance laboratory testing, shop trial assembly and structural integrity testing, construction of the prototype ICCT string in a suspended vertical well and installation of the ICCT prototype in ELAN's heavy oil lease at Cactus Lake, Saskatchewan. Also presented are the results of computer thermal simulations and ICCT field performance evaluation. In addition, a comparison of the advantages of the new ICCT technology with conventional jointed thermal tubing, is presented.
Soehlingen Z10: Drilling Aspects of a Deep Horizontal Well for Tight Gas
Authors: Pust G. , Schamp J.
Published: December 2007

Mobil Germany's pilot-project Soehlingen Z10 had the objective to make the large gas potential of the Main Sandstone of the gasfield Soehlingen (more than 40 Billion m3 of gas-in-place) producable at economic production rates. Due to the presence of Illite, the Main Sandstone has a reduced permeability of only 10 to 20 jxD. Offset wells had proven that economic production rates are achievable by means of hydraulic fracturing.

The drilling phase was completed in July 1994 following an extensive completion and stimulation phase with four hydraulic fracs in the horizontal section of the well. A 5750 m well with a 630 m horizontal section at a TVD of 4780 m under 92 degrees inclination was drilled. Drilling the well broke several records, being the deepest horizontal well drilled and logged with the deepest liner run to TD, cemented, completed and stimulated. In the horizontal section, the deepest plug back and sidetracking operation was carried out successfully.

To ensure the operational success, several long-term plan-ning and designing steps concerning the location of the wellsite, optimization of the wellpath, required minimum mud weight for the pay zone, secure drilling of the depleted Wustrow sandstone in the Rotliegendes above the payzone and proper running and cementing of the 7" liner in the horizontal section of the well took place in MEEG's drilling group to reach the high set goals of the project. Also a number of adjustments in the plan were implemented based on the actual conditions encountered in the well.

After finishing drilling operations the completion and stimulation works were performed successfully until the first production tests began at the end of January. Production from all four fracs yielded a rate of more than 20,000 m3 (Vn)/h, in comparison to the expected rate of 15,000 m3. These production statistics indicate the overall success of this highly difficult pilot project, which hopefully may lead to success of similar projects in the future on a worldwide basis.
The Paradox of a New Oil Province - Foinaven and Clair
Authors: Smith P. J. , Daly M. , Stump M.
Published: December 2007

Oil was discovered West of Shetland's as long ago as 1977 with the Clair discovery. However the first oil to be placed upon long-term production will not be until 1996 with the BP/Shell development of Foinaven. Developed during those 20 years is a wealth of experience gained by the offshore industry in discovering, appraising and developing oil fields in the UKCS providing the foundation for opening up the new West of Shetland Province.

The continued commitment to explore West of Shetlands, despite a sequence of non-commercial discoveries and dry holes led to the 1992 recognition of Foinaven and subsequently its fast track to development.

The paradox of twenty years from oil discovered to oil produced in a province, against 4 years for Foinaven discovery to market is the central inquiry of this paper.

Fundamental to understanding this paradox are:

the environmental constraints,

the development of new technology,

the awareness of the business prerogatives,

and the new behaviours of all stakeholders.

We take the case history of the Foinaven field development and discuss the requirements to bring this project forward.

Direct hydrocarbon detection seismic technology, novel well techniques and extended well testing provide the basis for volumes and productivity predictions. The employment of facility solutions in harsh metocean conditions and deep waters provide no less of a technological challenge. Understanding fully the business process and the importance of pace in development against the uncertainties that such a pace invokes is paramount. The quality and maturity of the UK offshore industry is an often forgotten component, along with the strides that oil companies and regulatory bodies have made in clearing hurdles for compliance in moving together at pace.

We are left with the challenge of developing, appraising and exploring simultaneously in a new province not knowing the full extent of volume, technology or behavioural change that it will require.
The Challenges of Liverpool Bay: A New Perspective for a New Era
Authors: Pearson R. G.
Published: December 2007

Unique technical, environmental, safety and managerial challenges characterise the Liverpool Bay development. Yet, at the same time, operator BHP Petroleum recognises the need to transform costs associated with the project. This paper focuses on the initiatives which meet the challenges and ensure the development will be completed on time and within budget.
Re-Engineering the Alliances and Partnerships
Authors: Straughen M.
Published: December 2007

Introduction

For some time the Offshore Industry has recognised the need to change the way it conducts its business if it is to retain a viable economic position in the future.

I presented a paper almost three years ago in Aberdeen that considered the issue of Improving the Competitiveness of the UKCS Offshore Industry. I believe this conference is an ideal opportunity to review what has been achieved since then and what further action is needed if any, with specific regard to the issue of Alliance and Partnership Relationships.

Industry Challenges

I summarised the huge challenges that the offshore industry faced then as follows:

New Development Undeveloped fields on the UKCS are more marginal in economic terms and will not be viable if their development is tied to traditional means because since the early 1980s, offshore costs have doubled while the oil price has about halved.

Producing Fields The revenue generated by the majority of these is in decline. In addition the effort to maintain existing platforms is increasing as the installations age, and added expenditure is necessary to accommodate the changes demanded by the new safety regime in the UK.

Competition The industry is operating on a global basis, and other areas of the world hold economic attractions for the operators, particularly for new developments. While the UK's political stability and advanced offshore infrastructure are attractive features, lower pricing can be found elsewhere.
Workforce Involvement in the UK Offshore Oil & Gas Industry
Authors: Royle D. J. C.
Published: December 2007

Workforce involvement has received much attention in the UK offshore industry since the Cullen Report in 1990. The concept is, of course, well known. Its application to offshore safety by operators and contractors has provided the opportunity to make full use of the experience and knowledge of the whole offshore population in a controlled effort to improve safety performance. Cultural and economic pressures are reinforcing the need to maximise the full potential available from the workforce while allowing management to exercise their legitimate control. Real benefits have been achieved including improved understanding and contribution to QRA work and in the handling of emergency situations wherfe other groups effectively become an addition to the existing workforce. As safety performance improves it becomes progressively harder to achieve further gains. A genuine and enduring participation by the workforce and line management in all issues affecting safety is needed if the current progress is to be sustained.
HIPS Design and Applications
Authors: Moroney Michael C.
Published: December 2007

A High Integrity Protection System (HIPS) is a safety mechanismfor a process plant offering the same or better protection than a relief valve or rupture disc. Thecurrent standard for plant protection in the United Kingdom is EEMUA Publication 160', whichgives four basic categories for control and protection systems:

Category 0 System. A self acting mechanical device or system which is a protectionagainst dangers to personnel. Examples include relief valves, bursting discs or containment.

Category 1 System. A non self-acting system whichrequires an outside source of energy and which is a protection against the dangers to personnel.

Category 2 System. A system which protects against the damage to the environment, damage to the process plant, loss of product or production.

Category 3 System. A control system which ensuresreliable production and maintainsplant operation within the operational limits.
Recent North Sea Experiences Involving Fatigue Failures of Duplex Stainless Steel Piping Systems
Authors: Jungbauer David E. , Smalley Anthony J. , Linzi Paolo
Published: December 2007

During the past 15 to 20 years, duplex stainless steels have gained wide acceptance in the oil, gas, chemical, and refining industries. Because of their desirable mechanical properties of corrosion resistance, high strength, and light weight, the offshore oil and gas industry has been quick to recognize their usefulness. Engineering design firms have been using duplex stainless steels to greater advantage to further reduce topside weight.

When using duplex stainless piping systems, thin-wall sections can pose serious dynamic problems. Even though their fatigue properties appear to be superior to most carbon steels, many fatigue failures involving duplex steels have occurred in North Sea operations. In systems experiencing little or no mechanical dynamic excitation, fatigue failures will not be a problem. Conversely, thin-walled systems exposed to flow- induced excitation due to low frequency random turbulence or high frequency sonic, or near sonic, flow conditions involving pressure control, recycle, or safety relief valves, can be highly susceptible to fatigue failures. These failures can occur at vibration amplitudes previously considered safe in thicker wall piping systems.

Failures of this kind were experienced during the start-up of the Tiffany Platform in small diameter branch connections attached to thin-wall duplex steel gas compression piping and, although affecting only a very limited number of connections, they were symptomatic of the problems recently experienced by a number of North Sea operators.

This paper describes the problems experienced and the approach used by AGIP (UK) Limited, together with Southwest Research Institute to investigate the causes of the failures and to identify simple remedies to allow quick restoration of safe production operations. The methodology used in obtaining data such as modal impact, vibration, noise, pressure pulsation, and dynamic strain are presented. Analysis to define the nature of the problems is also discussed. The solution of the fatigue failures is set forth along with suggestions for additional research that should be performed to develop guidelines and procedures for existing and new installations.
High Efficiency Inertial Phase Separation for Offshore Platforms
Authors: Brewer Richard J. N. , Pink David J. , Atkins David
Published: December 2007

The separation of immiscible liquids and the removal of liquids from gases by equipment utilising inertial and gravitational mechanisms has been an integral part of offshore production operations since the first platforms were constructed. There have been few significant changes in the basic technology over the years until the recent introduction of high efficiency membrane coalescers.

This paper presents the latest experience and technology for high efficiency membrane phase separation which has only recently become available.

The paper presents a review of the theory of phase separation and equilibria along with a discussion of the key factors controlling equipment size. Different technologies will be compared and a methodology for equipment selection presented.

Finally, specific details will be given of three offshore applications detailing how this proven technology has solved real problems on gas separation and ensured that fuel specification is achieved to a gas turbine by an innovative use of a high efficiency liquid / liquid separation unit.
Workover Applications to Eliminate Sand Production in V-Fields Horizontal Wells
Authors: Paul D. R. , Burton R. C. , Davis E. R.
Published: December 2007

This paper describes the workover and recompletion methods used to eliminate sand production on two horizontal wells identified as sand producers. The paper discusses the selection and performance of non-damaging drill-in-fluids utilised during the workover operations. The specific procedures to install prepacked screens and clean up the wells while minimising productivity impairment are presented. Results show the workovers eliminated sand production without significantly reducing well productivity, proving this is a viable method for future well interventions.
A Novel Scale Inhibitor Chemistry for Downhole Squeeze Application in High Water Producing North Sea Wells
Authors: Hen J. , Brunger A. , Peterson B. K. , Yuan M. D. , Renwick J. P.
Published: December 2007

This paper presents a novel scale inhibitor chemistry for achieving cost effective and extended squeeze lifetime in high water producers that can significantly reduce the number of treatments. The new and proprietary concept called Mobil Scale Inhibitor Process (MSI) is based on additives in the scale inhibitor solution that activate the phase separation of up to 85% of the total injected inhibitor during the well shut-in period following afterflush. Such an inhibitor retention is much higher than obtainable by conventional adsorption or precipitation mechanisms. The activation is temperature, time and pH driven and allows the inhibitor slug to be safely displaced into the formation before phase separation occurs. Furthermore, this squeeze chemistry am be applied to most of the commonly used scale inhibitors such as phosphino-polyacrylic acids (PPAA), polyacrylic acids and phosphonates to improve their squeeze performance. MSI is environmentally friendly and has an OCNS (Offshore Chemical Notification Scheme ) category of zero.

In corefloods with either PPAA or phosphonates under simulated North Sea reservoir conditions, this new chemistry resulted in a 2-12 fold increase in the squeeze lifetimes. Computer modeling predicts significant increase in inhibitor lifetime when applied in the field. To date, field trials by Mobil North Sea Limited support the laboratory work and well productivity was not damaged.

This new technology is believed to be a significant advance in achieving long-lasting and cost-saving downhole squeeze treatments for preventing scale deposition, particularly for for high water producing wells. Furthermore, it does not increase complexity in field operation when compared with conventional treatments.
Cost Effective Strategy for Modification Projects
Authors: Lunde Helge , Sirevaag Alf Morten , Tjåland Kjell
Published: December 2007

For an oil company involved in offshore oil production, the ability too effectively execute modification projects offshore is mandatory for to be able to extract the maximum economic potential of the offshore operation. Experience has shown this to be very difficult and large cost and schedule over runs has been the rule rather than the exception.

Statoil has developed a total strategy for this kind of project. The key element here is to make a short term alliance work for this kind of project while employing effective work processes and tools. The contract utilises the best from traditional bidding and alliance contracts and employs an alliance principle by utilising a compensation and risk sharing scheme that promotes common project goals for the participants. The work processes are optimised for efficiency and quality by employing fully responsible and integrated project teams, tailored project tools and procedures and an experience data bank for this kind of project. To teach the skills and motivate the involved project personnel, a purpose built training course has been developed.

Experience so far has shown a reduction of total project cost of 20 - 50%. The overall strategy is still in an early stage of its development and the potential for further improvement and development is indeed present.
Successful Drill Cuttings Reinjection (CRI) Case History On A Subsea Template Utilizing Low Cost Natural Oil Based Mud
Authors: Reddoch J. , Taylor C. , Smith R.
Published: December 2007

This paper covers the drill cuttings reinjection engineering and operating techniques utilized by British Gas and Apollo Services, on the three year Tunisian Miskar project off the coast of Sfax, Tunisia. At the time of this writing, British Gas has completed the subsea template phase, including the drilling and cuttings injection on 9 wells. A platform was installed in the last quarter of 1994 and the second drilling phase of this project began in March of 1995. A total of 11 or more wells are planned over a 3 year period.

Environmental regulations prohibited the dumping of oil based mud in the sea. Thus, if British Gas wanted the high penetration rates and, limited hole problems achieved by utilizing low cost, natural oil based mud, then cuttings reinjection presented the cost effective alternative.

All waste, from 8 wells, has been successfully pumped down three of the annuli with great success. Insignificant downtime has been experienced due to the injection process, even at instantaneous penetration rates in excess of 200 meters per hour on 12 1/4 inch hole. The CRI contractor rigged up and operated, with one man per 12 hour tower, the cuttings transfer system, the cuttings grinding/slurrification system and the triplex pump cuttings injection system. Over 2000 meters of limestone/claystone was encountered in each well while drilling and injecting successfully, (in the frac mode), into an impermeable claystone formation.

Addressed in this paper are: Well Planning with information on template drilling as it relates to cuttings reinjection.Injection well disposal design and planning, including multiple well casing points, for development drilling while producing.Requirements for surface equipment, personnel and commissioning.Field Results and Data with adjustments for unplanned events.Economics of CRI and natural oil base verses synthetic (psuedo) oil mud.Conclusions and recommendations for future work.
SYNENERGI - Production Chemicals and Process Design
Authors: Kaasa Øyvind
Published: December 2007

More cost effective oil production is possible if process design engineers start treating use of production chemicals in a more systematic way when they design new production platforms. Typically it is not common to include the effect of foam breaker and emulsion breaker when sizing separators. Design criteria for separators like foaminess and size of water droplets have little value when sizing separators if it is used without evaluating the positiv effect of the production chemicals. Testing on some of Norsk Hydro’s offshore facilities have shown that water treatment plants are not able to operate according to design without using emulsion breaker and a polyelectrolyt at low water cuts. Testing also indicates that a small oil stream from an oil sump can "polute" the oil-water separation system in the main separators because of its high content of surface active materials.

Injection systems for production chemicals are often added to the process on a "just in case" basis. Considering the importance of chemicals such as emulsion breaker and a polyelectrolyte, which are both vital to the quality of the water effluent, the process engineer should ensure that these chemicals work at optimum conditions. Parameters like temperature, concentration of active chemical component, and retention time in the pipe upstream of a processing vessel are important.

At the same time the oil companies requires that "green chemicals", combined with use of less chemicals in the effluent, to be used as part of their environmental policy. Unfortunately "green chemicals" are often less effective that other chemicals, making it difficult to reduce the amount of chemicals going overboard. The answer to the problems is to integrate the use of chemicals in the process design in order to achieve a synenergi effect.
A New MWD Concept for Geological Positioning of Horizontal Wells
Authors: Nakken E. I. , Mjaaland S. , Solstad A.
Published: December 2007

A key requirement in extended reach and horizontal drilling is to maintain the borehole trajectory within the productive interval. This is important for maximizing hydrocarbon recovery particularly when drilling thin beds and complexly folded and faulted reservoirs. The task, however, is often frustrated by uncertainty attached to the reservoir geology. This paper presents the conceptual ideas of an acoustic reference system for geological positioning of deviated and horizontal boreholes performed while drilling. The primary objective has been to extend the radial detection range from a few meters as of current geosteering tools up to at least 20 meters. By using acoustic reflection techniques, the borehole position is referenced to acoustic reflectors identifying critical stratigraphie bed boundaries or contacts. Theoretical analysis and experimental results, including cross well measurements with a full-scale prototype, demonstrate the feasibility of applying acoustic referencing for geosteering purposes.
The Use of CT Scanning in the Investigation of Acid Damage to Sandstone Core
Authors: Bartko K. M. , Newhouse D. P. , Andersen C. A. , Treinen R. J.
Published: December 2007

CT scanning1 has been used in acid flow studies in the past but has provided only qualitative information along the length of the core. A procedure for acid flow studies has been developed using a dual energy method on a CT scanner. This method determines the porosity change in volume elements in sequential axial slices along the length of the core. This paper describes the laboratory procedure used for the CT scanner to determine a treatment volume that is related to the volume of siderite in the formation.
Screenless Frac Pack Completions Utilizing Resin Coated Sand in the Gulf of Mexico
Authors: Kirby R. L. , Clement C. C. , Asbill S. W. , Ely J. W.
Published: December 2007

Removal of near wellbore damage and implementation of sand control through the use of Frac Packs with Gravel Pack screen in the hole is well documented in the Gulf of Mexico. However, an alternate procedure utilizing resin coated sand and conventional frac technology without Gravel Pack screens is now available. This paper describes the flexibility of such completions where multiple zones are encountered and the initial completions can be set up for future thru-tubing recompletions. In addition, the success of Frac Pack workovers on wells which were currently producing but rate restricted due to sand production is presented.

A discussion of well selection criteria, frac job design, gel systems, resin coated proppants, and field procedures is an integral part of the paper. Actual case histories are used to verify the success of the technique.

Frac Pack completions without screens in the hole are simpler and more versatile than those employing screens. Wells which encounter multiple small intervals which would not justify rig recompletions can be set up initially to facilitate future operations thru-tubing. By selecting the proper gel systems and resin coated proppants, formation damage removal, sand control, and stimulation can be realized without the use of screens. Field results back up screenless completions, recompletions, and workovers for small zones with less than thirty feet of perforated interval.
The Applicability of Current Slimhole Hydraulics Algorithms Under Field Conditions - A Critical Review
Authors: Thonhauser G. , Mülheim K. K. , Leoben Mining U. , Spoerker H. F.
Published: December 2007

Numerous publications have addressed the problems inherent to calculating well hydraulics in slimhole applications Accurate grasp of well hydraulics is of increased importance under slimhole conditions. Most models are valid in a controlled environment, but fail to fulfill the expectations under field conditions. Factors influencing the hydraulic behavior of the well have to be critically examined, and the accuracy of these factors entering into the calculations has to be quantified together with their relative impact on the results.

This work has compared several "established" approaches with field data from five deep slimhole wells, and critically reviewed limitations and possible advances in slimhole hydraulics’ calculations.

Analyzing field data showed phenomena that are not considered in existing simulations. This work tries to define these phenomena and evaluate their impact on future simulations. These factors influencing pressure loss and ECD development are listed and quantified, and examples from well data are presented.

A successful development of simulators of such complex systems is demanding a new way of thinking, away from the deterministic towards a probabilistic view of the problem.
Fiber/Proppant Mixtures Control Proppant Flowback in South Texas
Authors: Howard P. R. , King M. T. , Morris M. , Féraud J. -P. , Slusher G. , Lipari S.
Published: December 2007

Backproduction of proppant from hydraulic fractures (proppant flowback) is a continuing operational problem in the oil and gas industry. Up to 20% of the proppant can be flowed back after the treatment.1 Curable resin-coated proppants are used to control proppant production, but are known to chemically interact with fracturing fluids and may be prone to several failure mechanisms.2 Curable resin-coated proppants also require either well shut-in or the use of activators at low temperatures.

A new method to control proppant flowback relies on fibers mixed with the proppant to stabilize the proppant pack. The main advantage of this patented3 technology is that it is physical rather than chemical. Therefore, proppant flowback is controlled without specific shut-in time, temperature, or pressure constraints.

This paper presents flowback results from fractures of dry gas wells (<l millidarcy permeability) where fí-ber/proppant mixtures were used to control proppant flow-back (11 cases). Fluid flowback rate, gas rate and proppant production were monitored during the cleanup period. These wells are compared to wells where either curable resin- coated proppants or no flowback control were used (15 cases).

The fiber/proppant mixtures controlled flowback of proppant for both sand and ceramic proppants when used with all the proppant or in only the last part of proppant (tail-in). Flowback could begin right after the fracturing equipment was rigged down (15 to 30 minutes). Cleanup fluid flow rates were up to ten times higher than previously obtainable with curable resin-coated proppants and less proppant was flowed back. Faster flowback rates also resulted in earlier onset of gas production and reduced flowback time. Fibers allow greater latitude in flowback rate than curable resincoated proppants without the need for shut-in time.
Plug Cementing: Horizontal to Vertical Conditions
Authors: Calvert David G. , Heathman James F. , Griffith James E.
Published: December 2007

This paper presents an in-depth study of cement plug placement that was conducted with large-scale models for the improvement of plug cementing practices and plug integrity. Common hole and workstring geometries were examined with various rheology and density ratios between the drilling fluid and cement. The critical conditions dictating the difference between success and failure for various wellbore angles and conditions were explored, and the mechanisms controlling slurry movement before and after placement are now better understood. An understanding of these mechanisms allows the engineer to better tailor a design to specific hole conditions.

Controversial concepts regarding plug-setting practices have been examined and resolved. The cumulative effects of density, rheology, and hole angle are major factors affecting plug success. While the Boycott effect and an extrusion effect were observed to be predominant in inclined wellbores, a spiraling or "roping" effect controls slurry movement in vertical wellbores. Ultimate success of a cement plug can be obtained if allowances are made for these effects in the job design, provided all other previously published recommended placement practices are followed.

Results of this work can be applied to many sidetracking and plug-to-abandon operations. Additionally, the understanding of the fluid movement (creep) mechanisms holds potential for use in primary and remedial cementing work, and in controlling the placement of noncementitious fluids in the wellbore.
Fracturing Pressures And Near-Well Fracture Geometry Of Arbitrarily Oriented And Horizontal Wells
Authors: Chen Z. , Economides M. J.
Published: December 2007

The hydraulic fracturing of arbitrarily oriented and horizontal wells is made challenging by the far more complicated near-well fracture geometry compared to that of conventional vertical wells. This geometry is important both for hydraulic fracture propagation and the subsequent post-treatment well performance. Fracture tortuosity of arbitrarily oriented and horizontal wells is likely to cause large initiation pressures and reduction in the fracture widths. This paper presents a comprehensive study of the effects of important variables, including the principal stresses, wellbore orientation, and perforation configuration on fracture geometry. Initiation pressures, the contact between arbitrarily oriented wells and the fracture plane, and the near-well fracture geometry are determined and discussed. This study also shows that because of the near-well stress concentration the fracture width at the wellbore is always smaller than the maximum fracture width. This can have important consequences during hydraulic fracturing.
New 2-MHz Multiarray Borehole-Compensated Resistivity Tool Developed for MWD in Slim Holes
Authors: Bonner S. D. , Tabanou J. R. , Wu P. T. , Seydoux J. P. , Moriarty K. A. , Seal B. K. , Kwok E. Y. , Kuchenbecker M. W.
Published: December 2007

To address the increasing number of slim holes being drilled in the range of 5.75 in. to 6.75 in., a mixed-borehole- compensated (MBHC) 2-MHz array resistivity tool with a 4.75-in. collar diameter is described for resistivity measurement-while-drilling (MWD) applications. MBHC is a unique technique developed to minimize the effects of borehole rugosity. The new MWD array resistivity tool makes multiple MBHC phase shift and attenuation resistivity measurements using five transmitter-to-receiver spacings. Five independent MBHC phase shift and attenuation measurements are made at 2 MHz. The five phase shift resistivities have similar vertical responses but with increasing radial depths of investigation. The five attenuation resistivities are also vertically similar but coarser and are radially deeper than the phase shift resistivities. This new array resistivity tool effectively exploits the technology and the interpretation methodology recently developed for wireline induction resistivities and the benefits of multispacing probes for formation evaluation. Most of the petrophysical applications developed in conjunction with the wireline resistivity AIT* Array Induction Imager Tool are illustrated from MWD array resistivity logs acquired while drilling.
Automatic Parameter Estimation From Well Test Data Using Artificial Neural Network
Authors: Athichanagorn Suwat , Home Roland N.
Published: December 2007

We propose a robust way of achieving a well test interpretation by combining the sequential predictive probability method with an artificial neural network approach. The sequential predictive probability method considers all possible reservoir models and determines which candidate model or models best predict the well response. This method is dependent on obtaining good initial estimates for the parameters governing the candidate reservoir models, which is achieved by applying the artificial neural network approach. We use the neural network to identify the characteristic components of the pressure derivative curve corresponding to the flow regimes known to be in each candidate model. Reservoir parameters are then computed using the data in the identified range of the corresponding behavior.

As a final step, the candidate models and their initial estimates are evaluated using the sequential probability method. The method discriminates between the candidate models and simultaneously performs nonlinear regression to compute the best estimates of reservoir parameters.

The trained neural network was able to identify the characteristic components of the derivative curve in most cases. The algorithm written to interpret the neural network signals into flow regimes required special procedures to take care of the misclassification from the neural network. The initial estimates of reservoir parameters from the neural network were found to be reasonably close to the eventual estimates from the sequential predictive probability method.