bluuebunny/crossref_metadata_2025 huggingface dataset:
New Progressing Cavity Pump (NPCP) for Multiphase and Viscous Liquid Production
Authors: Bratu C. , Seince L.
Published: December 2007

This paper presents a new pump concept, called the New Progressing Cavity Pump (NPCP). The NPCP is composed of a Progressing Cavity Pump (PCP) and a system of Hydraulic Regulators (HR) installed inside the pump in between the cavities. The HR are self-regulated devices that recirculate the fluid between the cavities in order to control the pump thermo-hydraulic response and to avoid excessive built up of heat, which might result in premature failure of the pump's stator.

It is common knowledge that the traditional Progressing Cavity Pumps (PCP) have shown significant problems when dealing with multiphase mixtures, with high gas void fraction (GVF). We propose a new concept, NPCP, which is able to handle much better such conditions, as its internal hydraulic regulators (HR) recirculate fluid inside the pump. The benefits are multiple. First, it uniformizes the pressure across the pump length, which stabilizes the temperature. Second, it compensates the compressed gas volume of progressing cavities. Furthermore, it protects the stator and therefore, improves the pump's performance.

The relatively small dimensions of hydraulic regulators HR and their distribution along the pump result in an efficient multiphase design. Compared to traditional PCP, the new NPCP system better controls the reliability parameters, such as temperature and friction torque, reduces energy consumption and enhances hydraulic performance (flow rate, delivered pressure).

Several industrial NPCP have been manufactured and tested in liquid, both water and oil, as well in multiphase flow (air and liquid). This paper presents and describes the bench test results and shows that NPCP improves both reliability and hydraulic performance over existing pumps.
Sequential Multiwell Steam Huff ‘n’ Puff in Heavy-Oil Development
Authors: Shuhong W. , Yitang Z. , Liqiang Y. , Kequan Y. , Xia Z. , Chuntao L.
Published: December 2007

Steam huff and puff, generally thought of as a single well process, has seen interwell interactions such as steam channeling and/or watering out of neighboring producer by condensed steam at the later stage resulting in the poor production performance.

In contrast to the single well huff and puff (also named CSS), sequential multi-well steam huff and puff (SMWSHP) is a method in which some wells go to injecting, soaking and producing sequentially or at the same time. This method could avoid steam disturbance and interwell channeling and improve the production performance of huff and puff.

Feasibility study on sequential multi-well huff and puff in developing heavy oil reservoir is presented in the paper. The mechanism and sequence (manner and overlapped time) of SMWSHP and also the pilot test have been studied in a heavy oil reservoir from Xinjiang Oil Field. Both the field pilot test and the theoretical study show that SMWSHP could economically prolong the production period, improve the production performance of steam huff and puff, and increase the oil recovery by 5~7%. The mechanisms of SMWSHP are as follows: (1) Injecting steam into several wells at the same time can avoid the interwell steam channeling, extend the heating area and increase the reservoir pressure. (2) Injecting steam in various sequences could displace oil into different direction and so, improve the sweep efficiency.
The Role of the Value of Information and Long Horizontal Wells in the Appraisal and Development Studies of a Brazilian Offshore Heavy-Oil Reservoir
Authors: Branco Celso C. M. , Pinto Antônio C. C. , Tinoco Paulo M. B. , Vieira Paulo M. F. , Sayd Alexandre M. , Santos Renato L. A.
Published: December 2007

Recent exploration efforts in the Campos Basin, offshore Brazil, have resulted into important discoveries of what is known as "offshore heavy oil" (API gravities below 18 and reservoir viscosities above 20 cp). Actually, these accumulations have been known since the beginning of the development of the Basin, in the 80s, but they were never given a chance of development due to the technology challenges involved. The maturation of lighter oil fields, associated with recent technology developments (1,2,3), has boosted the interest for these heavy oil resources set aside for many years.

This paper describes a case history concerning the strategy for the appraisal of a large offshore shallow carbonate 12 API reservoir, at 100m water depth. To justify the investments in obtaining static and dynamic information of the reservoir behavior, a preliminary development plan based on long horizontal wells was established. The value of the new information (VOI) was estimated through the assessment of the impact that uncertain reservoir and production attributes could have on the development plan. Uncertainty analysis based on reservoir simulation allowed the identification of the main variables affecting the project: reservoir oil viscosity, permeability and effective footage of the horizontal well. This analysis revealed the best strategy for the appraisal of the well planning and led to the approval of a 2000m horizontal well.

On a second stage of the study, after the successful drilling and testing of the well, another VOI study was carried out, aiming at the evaluation of the benefits of a one-year extended well test, which is planned to start in 2007. At this stage, the main reservoir uncertainty was the aquifer support, which could relief the need for sea water injection (besides this there are other production uncertainties as flow assurance, performance of the pumping system and oil water separation).

This paper describes the simulation model building process, the difficult task of assigning scarcely sampled rock and fluid properties, the uncertainty study and the use of quality maps for placing the wells. Simulations results have shown the importance of the well footage and its effectiveness in contacting the reservoir rock.
Top-Injection and Bottom-Production (Tinbop) Cyclic Steam-Injection Method Enhances Oil Recovery
Authors: Matus E. , Mamora D. D.
Published: December 2007

We have developed a novel method to enhance oil production during cyclic steam injection. In the Top-Injection and Bottom-Production (TINBOP) method, the well contains two strings separated by two packers (a dual and a single packer): the short string (SS) is completed in the top quarter of the reservoir, while the long string (LS) is completed in the bottom quarter of the reservoir. The method requires an initial warm-up stage where steam is injected into both strings for 21 days; then the LS is opened to production while the SS continues to inject steam for 14 days. After the initial warm-up, the following schedule is repeated: the LS closed and steam is injected in the SS for 21 days; then steam injection is stopped and the LS is opened to production for 180 days. There is no soak period.

We have simulated and compared the performance of the TINBOP method against that of a conventional cyclic steam injector (perforated across the whole reservoir). Three reservoir types were simulated using 2-D radial, black oil models: Hamaca (9°API), San Ardo (12°API) and the SPE fourth comparative solution project (14°API). For the first two types, a 20×1×20 10-acre model was used that incorporated typical rock and fluid properties for these fields.

Simulation results indicate oil recovery after 10 years are 5.7–27% OIIP with TINBOP, i.e. 57–93% higher than conventional cyclic steam injection (3.3–14% OIIP). Steam-oil ratios are also decreased with TINBOP (0.8–3.1) compared to conventional (1.2–5.3), resulting from the improved reservoir heating efficiency.
Managing Well Integrity, Safety, and Production Decline Caused by Scale
Authors: Al-Ashhab J. K. , Petrone D. , Mokhtar S. R.
Published: December 2007

This work will describe the management of scale in a United Arab Emirates offshore carbonate reservoir. Field pressure is sustained by water injection, which contributes to the formation of scale in downhole tubulars. This scaling can cause both safety and production problems, for example, by blocking a subsurface safety valve or chocking flow at downhole nipples.

ZADCO has initiated a successful strategy to manage the sulfate-scaling tendency in the completion tubing. Software is used to identify wells early on as potential scale candidates. This software uses real field measurements and analysis of injected and produced water information. The results are used to plan well monitoring and/or treatment. The identified wells are monitored using both slickline gauge measurements to measure actual scale growth and produced water surface analysis to update the software model.

Early corrective action is performed using a specialized sulfate scale-dissolving fluid pumped from the surface. More aggressive treatment for larger scale accumulations is performed using a barge, coiled tubing unit, and specialized downhole jetting system.

Results have shown that early diagnosis of the scale allows earlier, easier, and far less expensive scale removal treatment. The effect of scale on production decline is also reduced.
Rheology of Heavy-Oil Emulsions
Authors: Alboudwarej H. , Muhammad M. , Dubey S. , Vreenegoor L. , Saleh J.
Published: December 2007

Water is invariably produced with crude oil. If there is enough shear force when crude oil and produced water flow through the production path, stable emulsions may be formed. This scenario may particularly be present during the production of heavy oils where steam is used to reduce the viscosity of heavy oil or in cases where submersible pumps are used to artificially lift the produced fluids. To efficiently design and operate heavy oil production systems, knowledge of the realistic viscosities of the emulsified heavy oil under the actual production conditions is necessary. This study is an attempt to investigate the effect of water content, pressure and temperature i.e. operating conditions on the viscosity of live heavy oil emulsions.

Two heavy oil samples from South America were used for this study. The stock tank oil (STO) samples were recombined with the corresponding flash gases to reconstitute the original reservoir oil compositions. Live oil-water emulsions were prepared in a concentric cylinder shear cell using synthetic formation water, under predetermined pressure, temperature, and shear conditions. The stability of live emulsions was investigated using a fully visual PVT cell, while viscosities were measured using a pre-calibrated high-pressure capillary viscometer. Viscosities were measured at least in three different flow rates at the testing conditions. In addition to live oil emulsion studies, the stability and droplet size distribution of STO emulsions were also determined.

Experimental results indicated that the inversion point for the stock tank oil emulsions was approximately 60 % water cut (volume) and that the average droplet size was increasing with water content. For all measured cases, viscosities varied with temperature according to an Arrhenius relation while viscosities did not indicate any variation with flow rate (shear) within the range of tested flow rates. Measured viscosities also increased as pressure decreased below the bubble point of the sample as lighter hydrocarbon components evolved. The measured viscosities increased as much as 500% due to the presence of emulsions before sharp drop in viscosity beyond the inversion point. The variation of viscosity with water content for live emulsion samples indicated that the inversion point for live emulsions is similar to that of stock tank oil samples.
Producing Extra-Heavy Oil From the Orinoco Belt, Cerro Negro Area, Venezuela, Using Bottomdrive Progressive Cavity Pumps
Authors: Ramos M. A. , Brown J. C. , Rojas M. , Kuyucu O. , Flores J. G.
Published: December 2007

Until 1995, in the Cerro Negro area within the Orinoco belt of Venezuela, rod pumping units and top-drive progressive cavity pumps (PCPs) had been the traditional means of artificial lift for vertical and deviated wells, with production rates ranging from 200 to 600 BOPD of extra-heavy oil (8°API gravity and viscosities of 2,000 cp at a reservoir temperature of 133°F). More recently, with the implementation of horizontal drilling technologies for the construction of wells in unconsolidated sandstones, electrical submersibles pumps (ESPs) became an alternative to handle higher production volumes1. Even more recently, top-drive PCPs have been installed in the Cerro Negro area to produce extra-heavy oil at high rates.

Hybrid artificial lift technologies, such as bottom-drive progressive cavity pumping, which combine features of the ESP and the PCP systems, have recently been successfully evaluated in the Orinoco belt to exploit extra-heavy oil reserves economically. A typical completion assembly includes a multisensor gauge to obtain downhole pressures, temperatures, vibration of the system, and power-cable current leaks; a 4-pole motor; protector; 4:1-ratio gear box; and the PCP. The functional design of the bottom-drive PCP facilitates the handling of viscous and abrasive fluids, increases the flow rate, and diminishes the operational costs. Advantages of this application also include the complete elimination of tubing wear by eliminating the rod string, greater torque capacity, lower surface maintenance, lower load and horsepower requirements, and less frictional losses.

The application of bottom-drive PCPs in the Cerro Negro area have resulted in production rates of up to 1,000 BOPD of extra-heavy oil with 50% less horsepower requirements in comparison to those of conventional top-drive PCP systems.
Pore-Level Investigation of Heavy-Oil Depressurisation
Authors: Shahabi-Nejad K. , Danesh A. , Cordelier P. , Hamon G.
Published: December 2007

Bubble nucleation, growth and mobilisation of gas are important phenomena encounter in oil production by the depressurisation process. The drive energy for oil production during pressure depletion is supplied initially by oil expansion but mainly by gas evolution from solution and expansion of reservoir fluids. Some heavy oil reservoirs in Venezuela and Canada show a high recovery factor during primary production under the solution gas drive process. Factors responsible for high oil recovery in heavy oil reservoirs are not well understood to allow reliable predictions to be made for economic evaluation of the process. A series of flow visualisation tests at the pore level was conducted using a high-pressure glass micromodel to identify the key features of the process.

A heavy crude oil, with a viscosity of 2500 cp at the bubble point pressure and API of around 10, was used to perform the tests at reservoir conditions. Micromodels with realistic pore pattern and different wettability characteristics, including oil-wet, water-wet and mixed-wet were used in the tests. A series of experiments was performed to study the effect of depletion rate, saturation history and water presence on the nucleation process, gas evolution and hydrocarbon movements.

Our observations highlighted the significance of test conditions, particularly saturation history and operational conditions on the nucleation process and bubble formation. Laboratory tests can produce a large number of bubbles formed by pre-existing micro bubbles activation, or a limited number of bubbles due to bulk nucleation, resulting in widely different depressurisation results. Hence, interpretation of laboratory data and its application to field performance would require particular considerations as identified in this study.

Critical gas saturation and subsequent gas/oil production are strongly affected by the critical value of supersaturation and the number of bubbles formed during depressurisation. Two generalised correlations have been developed to predict the above parameters at realistic reservoir conditions.

The experimental data generated in this study and interpretation of the results provide information on gas nucleation, critical supersaturation, bubble density and critical gas saturation, which are essential in field development planning and estimation of oil and gas recovery by depressurisation. The study also clears a number of ambiguities in the literature on prevailing mechanisms in depletion of heavy oil and contradictions between laboratory and field results.
Geomechanical Effects on the SAGD Process
Authors: Collins P. M.
Published: December 2007

SAGD (steam-assisted gravity drainage) is a robust thermal process that has revolutionized the economic recovery of heavy oil and bitumen from the immense oil sands deposits in western Canada, which have 1.6 to 2.5 trillion barrels of oil in place. With steam injection, reservoir pressures and temperatures are raised. These elevated pressure and temperatures alter the rock stresses sufficiently to cause shear failure within and beyond the growing steam chamber. The associated increases in porosity, permeability, and water transmissibility accelerate the process. Pressures ahead of the steam chamber are substantially increased, which promote future growth of the steam chamber. A methodology for determining the optimum injection pressure for geomechanical enhancement is presented, which allows operators to custom-tailor steam pressures to their reservoirs.

In response, these geomechanical enhancements of porosity, permeability, and mobility alter the growth pattern of the steam chamber. The stresses in the rock will determine the directionality of the steam chamber growth, and these are largely a function of the reservoir depth and tectonic loading. By anticipating the SAGD growth pattern, operators can optimize on the orientation and spacing of their wells.

Monitoring of the SAGD process is central to understanding where the process has been successful. Methods of monitoring the steam chamber are presented, including the use of satellite radar interferometry. Monitoring is particularly important to ensure caprock integrity, as it is paramount that SAGD operations be contained within the reservoir.

There are several quarter-billion dollar SAGD projects in western Canada that are currently in the design stage. It is essential that these designs use a fuller understanding of the SAGD process in order to optimize on well placement and facilities design. Only by including the interaction of SAGD and geomechanics can we achieve a more complete understanding of the process.
Recovery of Heavy Oil and Bitumen Using Disc-Stack Centrifuge Technology
Authors: Agrell J. , Faucher M.
Published: December 2007

Recent technological advances are making the exploitation of heavy crude oil reserves increasingly profitable. This paper describes the use of nozzle-type disc-stack centrifuges for dehydration of heavy oil.

The nature and composition of heavy oil leads to a number of undesirable properties, such as its tendency to form stable emulsions in the presence of asphaltenes, particles and other emulsifiers occurring naturally in the oil. This, combined with a high viscosity and a relatively high content of solids, makes dehydration a challenging task that introduces new concerns when compared to light crude oil.

As the density of the heavy oil increases and approaches that of water, conventional static and gravity-based separation systems become unacceptably large and require excessive heating and chemical addition to produce pipeline specification oil. Hence, the disc-stack centrifuge is proposed as an efficient solution in a compact size, enabling breakdown of stable emulsions and removal of dispersed water droplets and solid contaminants from heavy and viscous crudes, in both onshore and offshore installations.
Insights Into In-Situ Combustion by Analytical and Pore-Network Modeling
Authors: Akkutlu I. Y. , Lu C. , Yortsos Y. C.
Published: December 2007

In-situ combustion is a subject of continuing interest due to its rich interplay of flow, mass/heat transfer and reactions. The process complexity, however, has precluded its thorough understanding. In this paper, we provide some analytical results and pore-network simulations that explore fundamental aspects of this process.

The analytical approach relies on high-activation energy asymptotics. It consists of the assumption that the combustion front is a thin layer, within which reactions occur. We review our recent findings and derive exact results for the front temperature, the front propagation velocity and oxygen consumption. The results are then compared to pore-network simulations, where the effects of pore structure are included in a detailed simulation at the pore-network level. The simulations demonstrate the validity of the thin layer assumption and provide approaches for upscaling.

Then, the effect of porous medium heterogeneity, a ubiquitous feature of oil reservoirs, on the front is considered, in particular, in the form of a layered reservoir system. The fronts in two layers can be coupled under certain conditions, depending on the permeability-thickness contrast R between the layers, the extent h of external heat losses and the inlet conditions. We derive the parameter space, where this coupling occurs, and compare the results with the porenetwork simulations. Stability of the derived stationary nonequilibrium states is also analyzed. It is shown that the adiabatic states are always stable; whereas the non-adiabatic states being conditionally stable. This suggests that coherence of the fronts in the layered system is possible under certain conditions and that the effect of heterogeneity is not as detrimental to the process and its sweep efficiency, provided that heterogeneity does not exceed a certain limit, Rc.
Geomechanical Model of Oil Sands
Authors: Li P. , Chalaturnyk R. J.
Published: December 2007

Oil sands geomechanics plays an important role in the oil sands recovery processes, such as surface mining, cyclic steam stimulation and SAGD, which are widely applied in the development of oil sands resources in Alberta, Canada. Coupled reservoir geomechanical simulation techniques have been developed and used for the design of in situ recovery processes, particularly for SAGD. Thus, a realistic geomechanical model of oil sands material is a critical component in these reservoir geomechanical simulations. This paper presents the development of an oil sands model based on the analysis of laboratory testing results provided by different researchers, including Oldakowski, Samieh and Wong, and Touhidi-Baghni. On the basis of this analysis, 25 numerical experiments were conducted to match these laboratory tests, including the stress paths, as those applied in the laboratory experiments. Consequently, a comprehensive geomechanical model of oil sands material was established based on these numerical experiments. The proposed strain softening model parameters, such as the modulus of elasticity, peak and post-peak friction angle, and dilation angle, can be applied in the coupled reservoir geomechanical simulations of thermal recovery processes, including the SAGD process.
Recent Advances in Granular-Based Sand Control Design Operations and Their Performance Evaluation
Authors: Tovar J. J. , Webster C. M.
Published: December 2007

Sand control operations and particularly those using granular filter media such as gravel packs and frac & pack are being carried out in increasing numbers and in more demanding environments. Improvements continue to be made in terms of equipment, fluids and operations. However, with the increasing emphasis on well productivity and minimizing impairment, it is clear that a better understanding of some of the current causes of impairment is required.

The design of sand control filter media continues to be based on a limited number of discrete formation samples that are taken to be fully representative of the actual grain sizes throughout the interval of interest. It is often difficult to clearly identify the causes and location of the impairment unless expensive evaluation tools such as PLTs are utilized.

This paper presents the results of research work that have successfully resulted in an analytical tool and a new granular system that allows improved design and evaluation of sand control operations. A system for the determination of grain size and pore blocking mechanisms on a foot-by-foot basis has been developed. Furthermore a granular filter media has been devised such that permeability damage from solids migration can be reversed. The results presented are based on "flow of solid particles through porous media" principles. The work included laboratory testing for various gravels and these results are also included. Field validation was carried out with data from LDAs and an offshore deviated well.
New Applications of Well Log Parameters in Coalbed Methane (CBM) Reservoir Evaluation at the Drunkards Wash Unit, Uinta Basin, Utah
Authors: Yang Y. , Cloud T. A. , Van Kirk C. W.
Published: December 2007

The application of well logs in the CBM industry is usually limited to the identification of coal seams, coal thickness calculation, and estimation of gas in place1. In order to take full advantage of the abundant well log data collected at the Drunkards Wash Unit (DWU) and better understand log responses in CBM reservoirs, a study was performed with three major objectives. First, a new method was devised to calculate a permeability indicator using the shallow resistivity measured by the focused electrode tool. Second, the resistivity log was observed as a critical parameter to distinguish coal from non-coal formations in significantly enlarged well bores. And finally, based on the observed correlations between coal and log parameters, a comprehensive log cutoff system was established and a computer analysis model was developed to identify a diverse coal lithology system present at DWU.
Real-Time Optical Monitoring of Bottomhole Pressure During Extreme Overbalanced Perforating and Production Testing of a Remote Alaskan Exploration Well
Authors: Bond A. J. , Kragas T. K. , Mathias S. W.
Published: December 2007

Permanent downhole pressure gauges are becoming a standard completion component in many production wells. However, their use in exploration wells to date has been limited. Wireline-deployed memory gauges are more likely to be used to obtain downhole pressure data during testing of exploration wells. Unfortunately, pressure data from memory gauges does little to help the operator manage and optimize the completion and testing of a well where uncertainties in rock strength, pore pressures, and production rates can be high. Installation of a permanent downhole gauge in an exploration well can provide valuable data for real-time management of the production testing process. In addition, it can continue to monitor reservoir pressure after the well is shut-in.

This paper discusses the installation, application, and value of a permanent optical sensing pressure and temperature gauge system installed in an exploration well (Carbon #1) in the National Petroleum Reserve, Alaska (NPRA) during April 2004. The well was a delineation/confirmation well in a large hydrocarbon accumulation discovered during previous winter drilling seasons. All exploration work in the NPRA is done from ice roads and pads and therefore the season is limited by weather. Challenges and unique aspects of the installation included arctic winter operations, flawless integration of the data into surface well testing data acquisition systems and the ability to monitor real time bottom hole treating pressures during an EOB (extreme overbalanced) perforating treatment.

The real time data proved to be invaluable for determining the effectiveness of the stimulation treatment as well as optimizing the duration of the production test and final pressure build-up test. The ability to monitor pressure data real time rather than having to run and retrieve multiple memory pressure gauges provided nearly "textbook" data quality during multi-rate testing. The well is now temporarily abandoned and is available for use as a pressure monitoring well during future development. The results of the stimulation and well testing operation were very successful and will lead to a future commercial development in the NPRA.
Safety Is No Accident
Authors: Al Araimi N. , Mahajan M.
Published: December 2007

Well drilling and service operations generally involves heavy machinery, bulky equipment, heavy lifts, hazardous chemicals, challenging well conditions & worksites and tougher logistical elements. All these elements pose a challenge to the achievement of QHSE performance levels the oil and service companies aspire to achieve today. Over recent years, there has been a lot of learning, understanding and research work into these areas. These, coupled with a tremendous shift in awareness and attitudes towards the QHSE aspects of business, both in the operator and service sectors of industry, have brought in noticeable changes in the business environment. The role of QHSE performance now a days is not only limited to social dimension but it has become very decisive factor in the ultimate financial success of any business entity.

In Feb 2005 a major international operator in the Asia Pacific achieved a milestone of 6+ years LTI-free coiled tubing/well servicing operations. Considering that each and every job conducted throughout this six year period involved some combination of the several high potential hazards as stipulated above, this is indeed an achievement to be proud of.

A critical review of the whole process has been attempted in this paper to identify and highlight the critical components, which have played vital roles in the achievement of this great milestone. It is demonstrated that Safety is no accident; it is something we achieve by hard work, deep dedication, tremendous efforts and relentless follow-ups. We believe that the learning from this study would greatly contribute to improvements in safety performance of similar operations worldwide.
Application of Viscoelastic Fracturing Fluids in Appalachian Basin Reservoirs
Authors: Boyer C. M. , Glenn S. , Claypool B. , Weida S. D. , Crain C. D.
Published: December 2007

The Upper Devonian-age black shale of the Central Appalachian basin has been a major natural gas production reservoir since the initial discovery in 1921. In the ensuing 80 years, an assortment of drilling and completion techniques have been applied to the black shale with varying degrees of success. Recent efforts at improving well productivity have focused on improving the hydraulic fracturing operations, especially the minimization of fluid damage to the targeted shale reservoirs. The development of fluid systems with lower polymer loadings has been an important achievement in this effort. Recently, polymer-free viscoelastic surfactant-based (VES) fluid systems have been used in the hydraulic fracturing industry as a final step in the elimination of polymer-based damage. A statistical study of the application of a VES foam fracturing fluid in the Central Appalachian basin was performed. The study compared recent results of polymer-free treatments to traditional completions throughout the field. Results from the polymer-free completions were compared to immediate offsets drilled in the same time frame and completed in correlated intervals. In general, the use of polymer-free fluids improved well productivity, when compared to wells that were completed with a conventional polymer-based fluid. The study also compared the economic impact of the use of VES completion fluids from both an operations and production perspective.
Challenging the Traditional Coalbed Methane Exploration and Evaluation Model
Authors: Weida S. D. , Lambert S. W. , Boyer C. M.
Published: December 2007

Conventional wisdom states that a coalbed methane (CBM) evaluation program should consist, initially, of core hole and permeability testing, followed by flow testing wells, leading to one or more multiple well pilot programs. Such an evaluation program progresses sequentially from lower initial cost for basic data acquisition to higher cost production testing that normally focuses on the construction of a reservoir simulation-based field development model. However, Applications of this approach minimize any consequence of reservoir heterogeneities, which ultimately dominate later large-scale project performance. Due to these heterogeneities, potentially commercial coalbed methane production areas may be bypassed or prematurely condemned. To reduce the likelihood of missing or overlooking otherwise attractive CBM plays, an alternative evaluation model was developed to focus specifically on reservoir heterogeneity. This alternative evaluation program utilizes production distributions derived from proven productive basin area reservoir/operational analogs. The resulting production variability is then weighed against prospective new play areas in order to define more effective exploration program requirements. This results in a more realistic approach to the exploration process and increases the probability of large-scale technical and financial success.
Development of New 15Cr Stainless Steel OCTG with Superior Corrosion Resistance
Authors: Kimura M. , Tamari T. , Yamazaki Y. , Sakata K. , Mochizuki R. , Sato H.
Published: December 2007

New stainless steel OCTG (New 15Cr steel pipe: 0.03C-15Cr-6Ni-2Mo-1Cu) with high strength and superior corrosion resistance has been developed and its capability in oil and gas production environment is shown. The yield strength of the new 15Cr steel pipe was higher than 861 MPa (125 ksi), and good Charpy toughness was obtained in extremely low temperature condition. This material showed remarkably high strength even at high temperature of 200 degree C. The CO2 corrosion resistance was significantly improved so that the critical temperature for the developed pipe was more than 200 degree C at 15 MPa CO2 partial pressure. The superior corrosion resistance for revised the new 15Cr steel pipe was obtained by the higher amount of effective Cr in solution. In addition to this, the new 15Cr steel pipe showed good SSC resistance even in its high yield strength in the mildly sour environment. The good SSC resistance for this developed pipe was obtained by the good pitting resistance, induced from high Cr and Mo addition.
First Deepwater Application of Dynamic Annular Pressure Control Succeeds
Authors: Roes V. , Reitsma D. , Smith L. , McCaskill J. , Hefren F.
Published: December 2007

Shell Exploration and Production successfully deployed an automated bottom hole pressure control system developed by Shell International R&D called Dynamic Annular Pressure Control (DAPC) to solve lost circulation and hole instability problems in a deep water Gulf of Mexico well on the Mars Tension Leg Platform, after two failed sidetrack attempts. Dynamic Annular Pressure Control is a system designed to apply controlled annular surface pressure, with the goal of maintaining constant bottom hole pressure. Bottom hole pressure (BHP) can be maintained at any desired over/under balance by use of a lower mud weight than typical, and adjustment of surface backpressure as the circulation rate is varied.

In Shell's maturing deep water developments, rock stress redistribution due to reservoir depletion is causing drilling problems on a scale not seen in the past. High mud weights are still required for hole stability, but reduced fracture gradients have been observed both in reservoir and non-reservoir rock. DAPC was used in the third attempt to sidetrack the Mars A- 14 well, to keep Equivalent Circulating Density within the shrinking pore pressure / fracture gradient window.

The DAPC system was fabricated, installed and tested on a fast track basis after a review of the technology indicated a high likelihood of enabling the well to be drilled without problems. Cased hole tests indicated that BHP could be maintained within the required limits. The mud weight was reduced for the problematic section, and the well reached planned total depth without experiencing lost circulation or hole instability problems. The production liner was run and cemented without incident.

DAPC has been demonstrated as a promising new tool to solve drilling problems associated with reservoir depletion. As the technology matures, it has the potential for broad application to effectively widen the pore pressure / fracture gradient window in deep water, HPHT, extended reach and other challenging drilling environments by continuously and automatically maintaining a desired bottom hole pressure.
A New Industry Standard To Measure Rheology of Completion Fluids
Authors: Asadi M. , Penny G. S. , van der Bas F. , Brannon H. D. , Hawkins G. W. , Lord D. L. , McElfresh P. M. , Milton-Tayler D.
Published: December 2007

A new technical standard is developed to measure rheology of completion fracturing fluids. This method details step-by-step procedure for making fluids and rheology measurements. Completion fluids are defined for the purpose of this technical standard as viscosified treating fluids used during the completion or workover of a petroleum or natural gas producing well. The objective of this technical standard is to provide a standard procedure for measuring the viscous properties of single-phase, non-particulate-laden completion fluids. These fluids are viscosified brines, gravel pack carrier fluids, and fracturing fluids. These fluids can be either crosslinked or non-crosslinked (aqueous, hydrocarbon, or acid based). An optional shear history simulation procedure is provided for fluids that are potentially shear-sensitive. This procedure is designed to simulate the shearing effects experienced by a fluid in surface apparatus and during the time it is being conveyed down the wellbore.
A Compact Compensated Resistivity Tool for Logging While Drilling
Authors: Macune D. T. , Flanagan W. D. , Choi E. , Marcellus E.
Published: December 2007

A new method and tool design for borehole compensated electromagnetic propagation resistivity logging while drilling (LWD) are presented. The method provides borehole compensated resistivity measurements at multiple depths of investigation using a shorter antenna array than existing compensation methods. The compact array is typically 40% shorter than conventional antenna arrays for borehole compensated measurements, resulting in a shorter, lower cost bottom hole assembly (BHA). This paper presents the theoretical basis of the compact array design, as well as electromagnetic modeling results demonstrating performance in downhole conditions of interest. Results from field tests of a downhole tool are also presented.

The compact array design has been applied to create a shorter, lower cost resistivity logging while drilling collar. The three resistivity measurements enable determination of true resistivity (Rt), diameter of invasion, and flushed zone resistivity (Rxo) while drilling, geosteering, and formation evaluation in horizontal or deviated wells where application of wireline tools is difficult. The initial downhole antenna array design is some 44% shorter than equivalent conventional antenna arrays for borehole compensated measurements.

Electromagnetic modeling results are presented for the three-receiver and two-transmitter antenna array to demonstrate performance of the shallow, medium, and deep resistivity outputs from phase-difference measurements. Modeling and field test data are used to show equivalent performance of the compact array to existing compensated antenna arrays in rugose boreholes and at bed boundaries. Modeling results are also presented which demonstrate the limitations and advantages of multi-frequency operation. Test data for a new method for compensation of electronics error are also shown.

The paper presents a new approach to LWD borehole compensated resistivity methods that reduces the overall length of the antenna array and associated cost. The compact antenna array provides improved invasion profiling and determination of true resistivity when compared to existing borehole compensated array designs.
Worldwide Field Applications of a Polymeric Gel System for Conformance Applications
Authors: Eoff L. S. , Dalrymple E. D. , Everett D. M. , Vasquez J. E.
Published: December 2007

Water production becomes a major problem as hydrocarbon producing fields mature. Higher levels of water production result in increased levels of corrosion and scale, increased load on fluid-handling facilities, increased environmental concerns, and eventually, well shut-in (with associated workover costs). Consequently, producing zones are often abandoned in an attempt to avoid water contact, even when the intervals still retain large volumes of recoverable hydrocarbons. Many polymer systems have been applied over the years to control undesired water production from hydrocarbon wells, with varying degrees of success.

For approximately eight years, a polymer system based on an acrylamide/t-butyl acrylate copolymer (PAtBA) crosslinked with polyethyleneimine (PEI) has been used successfully for various water shutoff applications. This paper will describe results from a sampling of over 200 jobs performed throughout the world, including the average results from over 90 jobs performed in one geographic location alone. In addition to "standard" matrix treatments, results will be shown for other types of treatment, including a design to plug annular communication and a combination of sealant and temporary gel in an openhole horizontal completion. In addition, laboratory data pertaining to work aimed at increasing the temperature limit of the system will be presented. The upper placement temperature of the system originally was ~260°F. Data presented in this paper indicates the development of a retarder system that allows the upper placement temperature to be raised to at least 350°F.
Ultralightweight Cementing Technology Sets World Record for Liner Cementing With a 5.4 lbm/gal Slurry Density
Authors: Kulakofsky D. , Paredes J. L. , Morales J. M.
Published: December 2007

In an effort to meet increased demand for petroleum products, operators are drilling in more challenging environments. In Mexico, meeting the new challenges is requiring more skills and innovative materials from oilwell cementing providers. Nowhere else in the world have service providers attempted cementing across more depleted zones or weaker formations. Current cementing technology may not ensure successful circulation and an effective seal, which can have a great impact on (1) the cost of drilling a well and (2) the productive life of the well. In addition to the easily quantified cost of often-required remedial work, additional costs that are more difficult to quantify can be incurred from delays in production delivery and early water production.

Traditionally, the industry has relied on two very different technologies for the creation of ultra-light (densities < 10 lb/gal) cement slurries. The current technology involves either (1) the creation of a foamed cement using nitrogen or (2) the addition of lightweight microspheres (LMS) (sg < 1.1) into the cement. While both of these technologies are capable of producing very light cement slurries, neither of them has been used in an oil well to form an effective seal at densities below 7.3 lb/gal. In these most difficult Mexican formations where fracture gradients range from 7.3 down to 6 lb/gal, current cement densities of 7.3 lb/gal or greater have reduced chances of successful circulation.

This paper presents case histories from Mexico showing how a melding of both of these technologies, foam and microspheres, were required to stretch current lower slurry-density limits, allowing us to meet extreme operational demands. Along with the case histories and laboratory data, guidelines are provided for the best use of these technologies at densities down to 5 lb/gal. Details provided from the case histories illustrate how the advantages of both technologies were maximized, while their limitations were minimized.
Employee Violence Risk Assessment
Authors: Kuo W. H.
Published: December 2007

Perhaps the worst nightmare of any supervisor is dealing with an employee who is violent. Nevertheless, before there is an actual violent episode, or a serious threat of violence, there are background information, past history, and behavioral clues to forewarn a supervisor of an impending event. Applying current forensic psychiatry knowledge, this paper provides supervisors with useful tools to recognize early warning signs for risk assessment.
Optimal Strategies for Dealing With Shift Work and Insomnia
Authors: Kuo W. H.
Published: December 2007

Shift work is associated with many major chronic health problems; moreover, night shift carries increased risk of attention lapses and accidents, and reduced productivity. Insomnia, circadian rhythm, age-related sleep changes, health effects and shift work, and useful night shift accommodation strategies are discussed.
Perforating an HP/HT Gas-Condensate Reservoir Overbalanced in Oil-Based Mud
Authors: Svela P. E. , Wennberg K. E.
Published: December 2007

Kristin is an HPHT gas condensate field which presents challenges at all levels. At present no solution is ready with regards to drilling in depleted reservoir, which means that most wells have to be drilled before production start. This results in a very limited production experience (well test at low rate) between the completion of each well.

Initially the Kristin field was planned completed using a stand alone screen solution and cesium formate based drilling and completion fluids. However it soon became clear that an additional completion solution and an alternative completion fluid needed to be evaluated.

Due to operational constraints overbalanced perforating was the only feasible solution and work was started to qualify a fluid system for this use. Different drilling fluids had already been tested for formation damage with regards to screen completion, and from this selection an oil based mud and a cesium formate based mud was chosen for further testing with regards to perforating. This testing was performed on an analogue rock to the Kristin reservoir emphasizing on rock strength and permeability as key indicators.

The preferred fluid was found to be oil based mud, and this fluid was recommended as perforating fluid for the first well to be perforated in the Kristin field.

Well 6406/2-R-3 H was perforated overbalanced in 2.06 sg oil based mud, April 2005 and subsequently cleaned up towards test equipment on the drilling rig.

This paper describes the work done to prepare and qualify a suitable perforating fluid for HPHT conditions, while trying to minimize damage. Furthermore the results from the test of the first well perforated overbalanced is described.