bluuebunny/crossref_metadata_2025 huggingface dataset:
Case Study: Aconcagua and Camden Hills Fields Utilize Intelligent Completions To Optimize Production and Reservoir Performance
Authors: Jackson Nielsen V. B. , Illeman J. , Guillory T. L.
Published: December 2007

As part of the Canyon Express project, four intelligent completions were installed in the Total Aconcagua Field and two in the Marathon Oil Camden Hills Field, Mississippi Canyon Blocks 305 and 348 respectively, in ultra-deepwater Gulf of Mexico. As a result of production optimization objectives and reservoir conditions, the intelligent completions have been utilized extensively to enhance field performance since installation and host platform commissioning in 2002.

With the use of direct hydraulic open/close valves, various zones have been shut-in and cycled open to optimize production. The objectives of this paper are to provide an overview of using intelligent completions to improve well performance, to discuss the reliability of the intelligent completion equipment three years after installation, and to qualitatively present the value proposition of reservoir management of intelligent completions.

Faced with reservoir depletion, suspected sand production, and water influx, the intelligent completions have proven themselves useful in the management of these assets.
Constructing and Completing the World's First Offshore Reformable CRA Multilateral Junction Well
Authors: Kjosnes I , Syrstad S. O. , Flormoelen R. A. J. , Førdedal H. , Nygårdsvoll K. , Hogg C. , Westgard D.
Published: December 2007

This paper describes the recent installation of a new re-formable corrosion resistant alloy (CRA) multilateral system in the Norwegian sector of the North Sea. Choosing a multilateral completion option allowed the operator to cost-effectively access more reservoir targets than would have been possible with a traditional horizontal well.

This multilateral deployment marked several industry "firsts": first combination of conventional casing exit techniques with formed metal junction technologies; first deployment of conventional gravel pack sand control systems in both legs of a level 5 multilateral system and first use of corrosion resistant alloy material in a re-formable multilateral junction system. The resulting multilateral offers full hydraulic isolation of the junction, optimum flow capability and selective through tubing accessibility into either leg.

The decision making process and evaluation criteria of the operator that led to this multilateral selection is discussed in this paper. Additionally, the formed metal junction approach that was chosen is explored and the installation sequence detailed. Finally, the results and lessons learned during the installation process and future status are addressed.
The Bacton (U. K.) Work Process Solution for Liquids and Gas Quality Management
Authors: Hudson J. D. , Kinghorn P. L. , McVinnie G. , Paterson P. A. , Proot M. M. J. , Doran S. M.
Published: December 2007

Historically, gas production to the Bacton gas terminal from the southern UK sector of the North Sea has been predominately lean gas. In the recent years fields producing richer gas have been added to the production system, bringing significantly increased condensate production. While the condensate is itself a valuable product, the increased volumes have raised a number of liquids management challenges both for offshore and onshore operations.

To address these challenges, a software-based operational guidance system has been deployed over a broadly integrated scope that includes onshore and offshore components. This system includes performance monitoring and operational guidance for the offshore compression stations, liquids and gas quality management for the offshore production system and operational guidance for the onshore plant. The implementation is well-aligned with SmartFields architectural approaches. This paper details the business case, the technical approach and the experience gained both in the implementation and operation of the system.
Turning a North Sea Oil Giant Into a Gas Field - Depressurization of the Statfjord Field
Authors: Boge R. , Lien S. K. , Gjesdal A. , Hansen A. G.
Published: December 2007

The Statfjord Field has produced about 635 million Sm3 (4 billion bbl) of oil and exported 68 billion Sm3 of gas. This equals to an oil recovery factor of 65% and a gas recovery factor of 48% of volumes initially in place. Currently, the field is producing at an oil rate of approximately 20 000 Sm3/d, which is about 17% of the plateau production rate.

The predominant drainage strategy has been pressure maintenance by water and gas injection. However plans to extend production life for the Statfjord Field even longer will require changing drainage strategy from pressure maintenance to depressurization. Estimates show that implementation of the new drainage strategy will lead to an increased ultimate gas recovery from 53% to 74% and an oil recovery factor of 68%. Lifetime for the Statfjord Field will be extended by approximately 10 years.

A change in focus from oil production to gas production has consequences both subsurface and topside. Key elements for implementing the depressurization of the Statfjord Field reservoirs are drilling and recompletion of approximately 80 wells which will be equipped with artificial lift and sand control, as well as topside modifications on the three existing platforms. This results in a high offshore activity level for several years on a field in production. A new gas export pipeline to the UK FLAGS system (Far north Liquid And Gas System) is necessary to provide sufficient offtake of the produced gas.

Implementation of a new drainage strategy on the Statfjord Field has also regional effects. Prolonged life time of the Statfjord Field installations leads to increased recovery for the Statfjord Satellites and opens for business opportunities in a longer term.
Case Study of Integrated Solutions Used To Locate and Extract Bypassed Hydrocarbons in the Mature Reservoirs of the Algyö Field, Hungary
Authors: Werovszky V. P. , Benedek L. , Tóth I. Vargáné , Tóth J. , Lövei A. , Palásthy G. , Olson J.
Published: December 2007

Globally, the provable reserves of new discoveries have been reduced, making the technological challenges of EOR/IOR and increased recovery factors even more important. Many of these same technologies can be tested for new discovery applications through extensive evaluation in mature, established fields.

This paper focuses on four primary areas: -Review the evolution of reservoir recovery technology in Algyö Field.-Outline the various IOR techniques and how they have enhanced production-Explain the science and methods of the innovative technologies that have allowed us to push the envelope of reservoir understanding and recovery further out over time-Emphasize reservoir simulation enhancement and pre- drill well path qualification through wellbore fluid saturation measurements extracted from existing wellbores

Pursuant to the discussion of the four areas above, we will emphasize in detail: -Geological and petrophysical environment-Production history-Increased oil recovery methods and associated uplifts as:

Utilizing horizontal wells, including planning, successes and challenges, direct application of carbon/oxygen ratio and pulsed neutron captures data to reservoir simulation enhancement and horizontal well planning in a field exploited mainly by water injection technology.
New Concept for Drilling Hydraulics
Authors: Vestavik O. M.
Published: December 2007

The feasibility of a new concept for drilling and lining of a well has been investigated. The patented concept is based on the use of a dual channel drill string, where one of the channels is used for the return flow from the well. A sliding piston in the annular downhole section of the well, is used for force and pressure control. The concept is suited for drilling with a liner, which optionally can be expanded in place in the same run. The concept has special advantages for improved downhole pressure control, and for safe and efficient drilling of reservoirs with challenging pressure zones.The concept is also expected to provide solutions for cost efficient drilling, especially for sub-sea wells.
Designing for a Healthy Working Environment–Engineering Practices and Tools Used in the Norwegian Petroleum Industry
Authors: Throndsen T. I. , Høivik D.
Published: December 2007

The paper will give an overview of the current practice in the Norwegian petroleum industry, with respect to systematic follow-up of design and construction. It is described how possible health risk and future working environment conditions at the plant during operations are assessed systematically during design and construction. The methods used have become highly professional tools for follow-up of design and construction through 20+ years of experience from the petroleum industry in Norway.
Monitoring of Mercury Content of Fishes near the Bongkot Platform, Gulf of Thailand
Authors: Dhanasin P. , Utoomprurkporn W. , Hungspreugs M. , Soponkanabhorn T.
Published: December 2007

Since mercury is known to be a naturally occurring component of geologically derived hydrocarbons in the Gulf of Thailand, the Bongkot Operation Marine Environmental Monitoring concentrated on the measurement of mercury content in commercial species of demersal fishes in the vicinity of the Bongkot Operation Platform. The main species studied were groupers Epinephelus areolatus, red snappers Lutjanus sebae, sharptooth jobfish Pristipomoides typus. But in the two most recent surveys, sharptooth jobfish was not available so it had to be replaced with other species e.g. painted sweetlips Diagramma pictum.

Before late in 1997, treated produced water from the production platform was discharged into the sea. This water contained certain amount of mercury. Since then, the treated produced water was re-injected back into the depleted gas wells. And less and less direct discharge was made until in the year 2002, the volume of produced water re-injected was over 99.9%. Hence, the seawater surrounding the Bongkot Platform showed only the background level of mercury in natural seawater and fish should not be contaminated with mercury. From the results of the fish monitoring in 1997, 1998, 2000, 2002, 2004, the mercury content in fishes appear to be lower, within the natural range of values among each individual fish of the same species. The exception is painted sweetlips which showed a slightly higher average in 2004 compared to the concentration found in 2002, although the number of this species used in the analysis was much smaller than other species. Equally large numbers should be used to ascertain this issue in the next monitoring survey.
Lessons Learned From Four Selective Water-Shutoff Treatments in Mature Reservoirs in Maracaibo Lake
Authors: Der Sarkissian J. , Venline Venline , Prado M. , Rauseo O.
Published: December 2007

Some of the most important oil reservoirs located at the Maracaibo Lake Basin are produced by a waterdrive mechanism. After four decades since the beginning of production, oil rates have declined mainly due to a continuous increase in water production.

These reservoirs are characterized by highly heterogeneous sandstone formations in which water channeling through high permeability strakes is a very common cause of water production. Another type of problem affecting production in these reservoirs is behind casing communication between producing sand and nearby water sands. Both problems have caused a rapid increase in the water-oil ratio of the wells, which in most of the cases were abandoned affecting considerably the oil recovery of the reservoirs.

This paper describes four successful selective water shutoff applications in producing wells from mature reservoirs at Maracaibo Lake Basin performed during the last seven years. The aim was to correct problems of channeling and behind casing communication. An elastic gel system of variable consistency with easily controlled gelling times was used. In some applications a gel-cement combination was necessary to improve results. Reservoir and well characteristics, diagnostic analysis and the different types of selective placement used are shown as key factors for success.

Using the elastic gel system the water production has been reduced to a minimum, obtaining an increase in wells productive life-time, which in global terms reaches a volume higher than 2 millions barrels of additional oil recovered.
Improving Safety Awareness—A Field Study
Authors: Gilmore T. , Gritto S. , Steinback S. , Clayton M.
Published: December 2007

Safety performance, safety awareness, and safety reporting are becoming more and more prevalent in the industry today, with progressively more operators paying greater attention to contractor Quality Health Safety and Environment (QHSE) Management. Contractor effectiveness in QHSE management is being used as means to eliminate a contractor who does not meet minimum established standards. Consequently, more resources now being placed upon preventative measures which reduce accidents and incidents, some of which are described in this paper.

Many QHSE Management programs fail due to a "Top Down" only approach. If the entire workforce, from bottom to top, is not convinced, an organization will just be going through the motions. They will not realize any real benefit and more importantly, will not be instilling the safety habits that make an HSE program successful. As managers supervisors and engineers, we recognize the importance and value added to an operation by implementing safety systems and by setting safety targets that continuously challenge us to improve safety. The question then becomes how to build safety compliance by engraining a safety culture into everyday activities and into each individual employee, using cost effective resources and with a synergy that compliments, not compromises, service delivery to the customer.

This paper outlines how to move from a "Top Down" safety management approach to one balanced by both employee and management feed back. The balanced approach to safety, through an example of the efforts made in one Oilfield Service Company operating location will be demonstrated. It explains how the message is passed on to and ingrained into the workforce to solicit their understanding, participation and "Buy-In". Once the workforce buys in, it is demonstrated that QHSE becomes second nature to all personnel. As everyone becomes involved, the number of days without a Lost Time Accident (LTA) starts to become a part of his or her daily life, rather than an abstract figure reported monthly by the manager. The importance of visible closure of action plans with continual feedback, has been shown to play a very important role in convincing the workforce that the system is real and that the company is serious about QHSE. This, together with a consistent zero tolerance policy and a no blame culture, will reinforce the most important factor - commitment.

This paper will also demonstrate that with the use of available management tools such as communication, management visibility, standard practices, employee empowerment, leadership by example, training, delegation, quality control, recognition & reward, and the setting of challenging and achievable objectives, a sustainable, successful QHSE program can be developed.
Utilizing an Automated Annular Pressure Control System for Managed Pressure Drilling in Mature Offshore Oilfields
Authors: Reitsma D. , van Riet E.
Published: December 2007

Shell International Exploration and Production B.V. Research & Development has developed an automated choke manifold capable of maintaining a relatively constant bottomhole pressure while drilling. The Dynamic Annular Pressure Control System prototype was successfully tested in 2003, followed by a long-term trial on a deep geothermal well in 2004, proving the robust nature of the design. Two new systems have now been prepared for offshore use. One choke system has been deployed for use in the UK sector of the North Sea and a hybrid system deployed in the Gulf of Mexico. Both applications require the bottomhole pressure to be maintained at a relatively constant value in order to maintain borehole stability. Both applications are in mature offshore oilfields where narrow pressure margins would result in borehole collapse if conventional drilling methods were employed. The development of the choke manifold systems, application and results will be discussed.
Packerless Multistage Fracture-Stimulation Method Using CT Perforating and Annular Path Pumping
Authors: East L. , Rosato J. , Farabee M. , McDaniel B. W.
Published: December 2007

Record high prices for oil and gas have increased the opportunity for producers to maximize the value of their assets. Under current market conditions, reservoirs previously considered marginal or even noneconomic can yield an acceptable return on investment and are increasingly considered for well completion. Many are lower-permeability formations that require fracture stimulation during the completion phase to deliver economic rates. In the latter part of 2004, a new stimulation technique was introduced to the industry, providing well operators a method to achieve multiple-zone fracture stimulation while controlling stimulation costs. By mid-2005, this new process had been evaluated by several operators in the US as well as Canada and Australia with very positive results.

This new process offers the opportunity to perforate and stimulate multiple pay zones with a single well intervention, often within a single day. The technique employs a hydraulic jetting assembly on coiled tubing (CT) to erode perforations, immediately followed by pumping a fracture-stimulation treatment through the annulus between CT and casing. At the completion of the first fracturing stage, small-volume, high-proppant-concentration slurry is left in the wellbore to provide isolation of the just-stimulated zone from subsequent targets. In some applications, a wellbore screenout may also be induced to improve the temporary isolation of this zone. This sequence (perforate, stimulate, isolate) is repeated until all desired zones have been treated. Following the final stimulation stage, the well is cleaned out with CT and turned over to production. If needed, N2 gas can be pumped through the CT to kick-off the return flow.

This paper describes the operational aspects, advantages, and limitations of using this new multistage perforating and fracturing technique with example field applications.
New PDC Technology Significantly Improves Performance in Drilling Deep Khuff Wells for a Major Operator in Abu Dhabi
Authors: Jaffar A. , Birch R. , Teasdale P. , Ani S. A.
Published: December 2007

Drilling the 12¼" and 8½" sections in offshore Abu Dhabi's Deep Khuff fields is very challenging due to an intricate geological sequence that consists of limestone, dolomite and shales that are highly interbedded with hard stringers. Historically, ADMA-OPCO, the operator, has attempted to efficiently drill the section using roller cone tungsten carbide inserts (TCI), natural diamond and polycrystalline diamond compact (PDC) technology.

PDC bits yielded better performance in terms of rate of penetration (ROP) and bit life over TCI bits. However, it required several PDC bits to drill the sections. Further detailed analysis produced optimum PDC designs that successfully established new benchmarks in the fields.

The objective was to minimize the number of bit trips by enhancing PDC bits performance. This called for new PDC technology coupled with optimized motor drive. To address this challenge, ADMA-OPCO and bit vendor and other service companies worked together to seek optimized solutions to drill the interbedded rocks efficiently.

This paper reviews the findings of the detailed study in drilling the 12¼" and 8½" sections in typical Deep Khuff wells. The study showed that PDC damage from encountering harder stringers was the primary impediment to achieving better performance. Subsequent to the recommendations, the challenges were overcome by utilizing new PDC cutting structure designs and advanced cutter technology along with optimized downhole motor assemblies. The resultant improvement is also demonstrated by examples from separate fields offshore Abu Dhabi where considerable savings were achieved in terms of footage drilled and cost per foot.
Deployment of High-Horsepower ESPs To Extend Brent Field Life
Authors: Blanksby J. , Hicking S. , Milne W.
Published: December 2007

The Brent field in the Northern North Sea is enjoying an extended life partly due to installation of electrical submersible pumps (ESPs) to back-produce water from the reservoir. ESPs have been deployed with some success to prolong reservoir depressurisation in order to replenish the gas cap for subsequent production.

This is the first offshore application of ESPs for this purpose and differs from water production from aquifer wells for reinjection purposes. Moreover it has not been achieved without overcoming technical challenges such as minimal control during start-up, the use of fixed-speed drives, operating high horsepower motors, and a large degree of sub- surface uncertainty.

The equipment selected for the ESP system is described, including downhole and topsides equipment. An extensive development and testing programme was undertaken to qualify the pump and motor design for this unusual duty.

Lessons learned from the testing, commissioning and operational phase of the project are discussed.
Improved Wavelet Filtering and Compression of Production Data
Authors: Olsen S. , Nordtvedt J. -E.
Published: December 2007

This paper investigates filtering and compression of real-time production data by means of wavelets. We conduct a comprehensive analysis examining a series of possible wavelets for this type of data, and demonstrate that spline39 and spline4246 have excellent properties for cleansing of pressure and rate data, respectively. We extend the wavelet filtering technique for E&P data in several ways. We demonstrate that the methods frequently used for noise estimation give erroneously results, and that the noise estimation will depend on the wavelet utilized. New noise estimators are developed. We show that the new noise estimators combined with a median filter are suited for removal of outliers. We demonstrate that the SCAD shrinkage rule gives best results together with spline39 for pressure and spline4246 for rate. We show the choosing a higher filter level than those common used will be beneficial. A new empirical threshold estimator is proposed, giving excellent results compared to the other commonly used threshold estimators. A new compression routine for automatically compression of signals is proposed, finding the optimal compression ratio for piecewise constant signals like rate data. The filter approach proposed in this paper requires no user interaction, and can thus be performed automatically. In most cases, noise reduction at 85% or above is achieved.
Laboratory Studies of In-Situ Generated Acid To Remove Filter Cake in Gas Wells
Authors: Nasr-El-Din H. A. , Al-Otaibi M. B. , Al-Qahtani A. A. , McKay I. D.
Published: December 2007

Many horizontal/multilateral wells are drilled using water-based mud. In general, drilling fluids consist of xanthan, starch or polyanionic cellulose with bridging agents like sized calcium carbonate and salt particulates. During drilling and completion operations, it is essential to form an external filter cake to control fluid losses. However, effective filter cake removal during well completion is very difficult to achieve, especially in low permeability formations. Increasing use of long horizontal and multi-lateral wells with very low draw-down makes efficient cleaning and stimulation treatments even more challenging. Placement of corrosive acids to dissolve carbonate is problematic particularly in horizontal wells with extended reach. Polymer-breaking enzymes and oxidizers are effective at degrading polymer residues present in the wellbore, but will not attack carbonate or other acid-soluble materials.

A new fluid addresses several key problems inherent in removal of drilling fluid filter cake, cleaning, and stimulation treatments of horizontal and multilateral wells. This fluid generates an organic acid (acetic or formic) in-situ, thus providing a very controlled acidising process for mud solids. The fluid can also incorporate enzymes to remove biopolymers. Several lab experiments were conducted to examine the compatibility of fluids with enzymes. The kinetics of acid producing reactions were examined in detail. A modified HPHT fluid loss cell was used to assess the effectiveness of the system in cleaning drill-in fluid damage. The surface tension of fresh and spent acid was measured as a function of temperature.

Lab results indicated that the fluid is compatible with the enzyme system. Also, the fluid is non-corrosive and has minimum impact on well tubulars. Unlike conventional reactive acids such as HCl, the slow reaction kinetics ensure better distribution of the new fluid across long sections with minimal leak-off during pumping. The HPHT tests showed a significant improvement in the efficiency of removing filter cake. Surface tension measurements indicated that the spent acid solution had low surface tension, which will accelerate lifting these fluids from tight formations.
Discharge of Produced Water in the North Sea: Where We Are, Where We Go.
Authors: Garland E.
Published: December 2007

Since the Paris Commission has taken its first measures regarding the discharge of produced water from offshore installations into the North Sea at the end of the 1970s, the provisional performance standard set at that time has remained unchanged. In fact that provisional performance standard (limiting the content of oil at 40 mg per litre of water discharged) was a challenge, and industry spent billions of $US to treat the billions of cubic meters of produced water which have been discharged since then. It led to the development of new treatment techniques, the prominent one being the hydrocyclones in the 1990s.

Measures taken by OSPAR in 2000 regarding chemicals used and discharged offshore and in 2001 regarding the management of produced water dramatically changed the picture, giving an impetus to development of new techniques - some of which being now fully implemented-,to reconsider water management, shut-off techniques, and last but not least, re-injection, a technique which, for many reasons, has been less used in the North Sea than in other regions of the world.

The global average oil content of the water discharged in the North Sea is significantly lower than the upper limit set by the regulators. Nevertheless, not only some installations still face serious difficulties to meet this old performance standard, but the measures taken by OSPAR at the beginning of the 2000s actually go far beyond that standard, create constraints on compounds in produced water other than aliphatic hydrocarbons, and development of new technologies as well as a review of the approach of the operators of produced water treatment and disposal routes need to be dramatically reconsider.
Optimization of Borehole Stability Using 3D Stress Optimization
Authors: Kårstad E. , Aadnoy B. S.
Published: December 2007

Borehole stability has played an important role in the evolution of long and deep wells in later years. Borehole collapse and circulation losses are costly problems for the entire drilling industry.

It is often assumed that high borehole inclination leads to lower mud weight margins. To investigate this aspect, a study of borehole stability in 3-dimensional space was undertaken. This paper presents results and applications of the findings in this study.

The in-situ stress state plays a key role for borehole instability. The stress state is usually classified as normal fault, strike/slip fault and reverse fault stress states. One major conclusion of the study was that optimum stability was obtained for a lithostatic stress state, which is where all 3 normal borehole stresses are equal. For this case the window between fracturing and collapse was maximum. Bounds on the magnitude of the in-situ stresses were also invoked, resulting in a constrained 3-dimensional model that covered both fracturing and collapse pressures.

Studying both fracturing and collapse pressures, it was found that maximum hole stability could be obtained at intermediate orientations, and that they are controlled be the magnitude and directions of the in-situ stresses.

Field cases are also presented in the paper. It is shown that under optimal conditions combination of wellbore inclinations and azimuths can give the highest wellbore stability.

The 3-dimensional fracture and collapse model presented is an efficient tool for well path optimization. Platform placement and planning of difficult wells can be improved by using this method. It is presented as analytical equations, and can easily be implemented in a calculator.
Calculation of Drillpipe Rotation Effects on Fluids in Axial Flow: An Engineering Approach
Authors: Hemphill T. , Ravi K.
Published: December 2007

The usefulness of drill pipe rotation in drilling and cementation has been debated over the past several years. In recent years, the positive effects of pipe rotation on hole cleaning, particularly in highly-deviated wellbores, has been noted. However, many engineers are unsure of the usefulness of drill pipe rotation because the effect has not been quantified. One reason for this is that the effect of drill pipe rotation on non-Newtonian drilling fluids in annular flow is not a well understood phenomenon. There has been no single, valid method developed to mathematically characterize rotation effects on point velocities for non-Newtonian fluids in axial flow.

In this paper, the effect of drill string rotation on axial flow is investigated from a fluid dynamics perspective. Using the Herschel-Bulkley rheological model, calculations for pure laminar flow and rotation are coupled to obtain shear rate characterization across the annulus. Developed first for fluids in concentric flow, these methods will be later expanded to handle the effects of drill pipe rotation in eccentric geometries.

Using this method to mathematically characterize the effect of drill string rotation on axial velocity can lead to better understanding of annular flow behavior under normal drilling and circulating conditions. Areas such as hole cleaning in high angle wellbores, rotation speeds necessary to effect good annular cleanup prior to cementing, etc., will find useful application for this mathematical modeling technique. Moreover, in today's complex wells where a narrow operating window exists between pore pressure and fracture gradients, any improved understanding of factors that change annular pressure drop and velocity patterns can be critical to the success of the drilling operation.
Optimized Test Sequences for Formation Tester Operations
Authors: Pop J. , Follini J. -M. , Chang Y.
Published: December 2007

The setting of pretest parameters for the acquisition of pressure and mobility data with wireline formation testers has largely been left to field engineers operating the tool and their knowledge of local conditions. If the test sequence is not successful the pretest parameters, such as the number of drawdowns, pretest volume, rate and duration, are either adjusted to achieve a better result or the tool is moved to a nearby location where the chance of success is deemed to be better. This strategy "works" if the information necessary to make an assessment is readily available. During drilling operations, where telemetry rates are usually very low and test times are necessarily short, this approach is not likely to be acceptable.

This paper describes pretest sequences that optimize the process of acquiring pressure and mobility data during formation tester operations without compromising the quality of the data. All sequences employed consist of three phases: identification when the mud cake has been breached and the sandface pressure is below formation pressure; a short "investigation" phase in which the formation is interrogated to obtain an initial estimate of its properties; and one or more "measurement" phases in which the best estimates of the formation pressure and mobility are obtained. The measurement phases use the information acquired during the investigation and/or previous measurement phases to design an optimal test sequence such that a stabilized sandface pressure is achieved at the end of each measurement phase subject to an overall time constraint. This is done in the downhole tool by solving a small- scale optimization problem. Associated with the sequences are quality indices derived from the results of the individual phases that indicate how well the procedure has succeeded and the validity of the data acquired.

The test sequences have been implemented on standard wireline formation tester tools and a formation pressure while drilling tool. Field trials with the new sequences are discussed and the results are compared with standard operating sequences.
Alaska Kuparuk North Slope Oil Separator Upgrade: Case Study
Authors: Lees R.
Published: December 2007

Located on the Arctic Coastal Plain, 40 miles west of Prudhoe Bay, ConocoPhillips Kuparuk facility on Alaska's North Slope is the second largest oilfield in North America. At CPF1, ConocoPhillips brought on a new field with heavy oil and high solids content which necessitated upgrading the 1st Stage production separator. The original separator level instrumentation, used for the past 23 years, utilised traditional displacers and differential pressure cells for both oil and interface measurements.

In an environment where extreme winter temperatures of minus 60 deg F (-120 deg F with wind chill) are the norm then high reliability and maintenance free operation comes very high in the specification of instruments. This case study shows, with operator feedback and ‘real time’ ‘on line’ screen shots and trending data, how various novel and traditional level measurement technologies performed under these conditions of extreme temperature and dealing with difficult to separate oil with a high solids concentration. The technologies under review included the Tracerco Profiler, Guided Wave Radar, internal displacers and external differential pressure cells.

"The new technology Tracerco profiler has been extremely helpful in identifying emulsion build-up, allowing us to attack it quickly with chemicals. We have also been able to improve the interface control tuning on the water outlet valves. We have not seen much foaming, but that may be because we are treating with a lot of antifoam. The sand monitoring capability was an unexpected benefit. Operations knew all along it could see sand, but we didn't expect to use it like we have been. We anticipated sandjetting the vessel about once per week as we have for the past 23 years, but with the new heavy oil field producing an order of magnitude more than that, knowing when to sand jet (almost daily now) has been a huge advantage."
Managing Safety—Focusing on High Potential Risks and Incidents
Authors: Sixma E. , Rutten K.
Published: December 2007

Over the last few decades, the Shell Group has been quite successful in reducing LTIF and TRCF by focusing on these indicators, but this has not resulted in an equally significant reduction in FAR.

One explanation for this is seen to lie in the fact that the incident "iceberg" has a significantly different shape for different classes of activities.

Focusing on reducing LTIF and TRCF can result in a focusing on the wrong class of activities, which actually contribute less to the overall FAR.
Nitrogen Injection in the Cantarell Complex: Results After Four Years of Operation
Authors: Sánchez J. L. , Astudillo A. , Rodríguez F. , Morales J. , Rodríguez A.
Published: December 2007

The nitrogen injection project in the Cantarell Complex, offshore Mexico, implemented in May 2000, has been the most ambitious pressure maintenance project around the world regarding incremental oil, production rate, nitrogen injection rate, and investment.

In this paper, the main drivers and objectives of the project, along with key issues that have been taken into account to guaranty success, are reviewed. A description of the data acquisition program implemented to monitor reservoir performance during nitrogen injection is discussed and results analyzed.

The pressure-production behavior of the reservoir during nitrogen injection is presented and results obtained after four years of operations are assessed, along with additional field development and benefits from updating and increasing facilities.
Numerical Modeling of Advanced In-Situ Recovery Processes in Complex Heavy-Oil and Bitumen Reservoirs
Authors: Card C. C. , Close J. C. , Collins D. A. C. , Sammon P. H. , Wheeler T. J. , Fortson N. G.
Published: December 2007

As development activities in heavy oil and in situ bitumen deposits have accelerated, the challenge of forecasting the performance of in situ recovery processes at field scale has increased exponentially.

Delineation drilling results make it apparent that these deposits are highly complex and three-dimensionally heterogeneous. Heterogeneity has a significant impact on the effectiveness and economics of the recovery process.

Many experienced operators are recognizing that in addition to the static complexity of the reservoirs it is necessary to consider the dynamic stress state in the regions undergoing production. Geomechanical factors are significant and must be built into any realistic numerical simulation of recovery processes.

It has become apparent to operators that modeling single well-pair operations may be misleading, and seven to ten well-pair models are now quite common.

All these factors result in increasing size and complexity of numerical simulation models.

Reservoir simulator developers have responded with two technologies to achieve reasonable run times in these large and complex models. The combined use of 64-bit symmetrical multiprocessor computers and dynamic grid refinement will be discussed and compared against traditional simulation methods.

This paper will provide examples of the application of these leading edge technologies for in situ oil sands development in the Surmont area of the Athabasca deposit.
Designer Casing for Deepwater HPHT Wells
Authors: Miller Richard A. , Payne Michael L. , Erpelding Peter
Published: December 2007

Deepwater high pressure, high temperature (HPHT) drilling environments present difficult challenges to well engineers. Typical deepwater pore pressure and fracture gradient profiles result in a narrow drilling window that can lead to seven to nine casing points. The high cost of these wells demands a high rate completion for economic payback, which defines the size of the production casing and liners. Drilling casings are restricted by the standardized 18-3/4" through bore diameter dictated by high pressure wellhead housings, blowout preventers, and riser systems. Furthermore, high pressures require thick wall casing, especially if sour service materials are specified. Satisfying all of these pressure and geometrical constraints requires some unconventional practices.

Current and emerging technologies offer several ways to address this design dilemma. Riser-less drilling can be an effective way to delay running the high pressure wellhead, allowing for additional large diameter casing seats. Dual gradient drilling is a concept that can decrease the number of required casing points. Solid expandable liners provide a way to add or push casing points without the geometry impact of a conventional string. Managed pressure drilling may also show promise for eliminating a seat. However, heavy reliance on these new technologies may run counter to the guiding principle of keeping HPHT wells as simple and reliable as possible.

This paper presents the concept of using conventional oil country tubular goods (OCTG) in unconventional sizes to increase the number of available casing points in deepwater wells. The method has several advantages in the areas of performance and reliability compared with the previously listed technologies. The decades of industry experience with conventional OCTG make the technology especially appropriate for containing high pressures and sealing off trouble formations.

Related issues such as manufacturing lead time, costs, connections, and hangers are discussed. Several HPHT examples are included to illustrate the trade-offs with other design options.
Alternatives for High Strength Materials in Sour Environments
Authors: Turconi G. López , Fukui T. , Ono T. , Pérez T.
Published: December 2007

Typical environments foreseen in HPHT wells put a high challenge for properties required for materials. Strength levels create severe limitations to improve toughness, resistance to hydrogen embrittlement and other corrosive agents responsible of both general and localized corrosion. High temperature service reduces the alternatives, because of effect on corrosion and also the reduction in strength at temperature. Internal pressure and well depth create a combination of stress that would lead to requirements of heavy wall thickness for tubulars. This, in turn, is a challenge for seamless tubular manufacture with actual production routes, particularly in the field of hot deformation and heat treatment.

Progress has been made in the design and production of low alloy carbon steel that somehow has reached the limit of actual metallurgy science. Other material alternatives, in the field of stainless steels and other corrosion resistance alloys can be also explored.

Another particular point is the development of methods for properties assessment in the expected environments. The reproductions in laboratory conditions, and the correlation with those in the field, are areas of research and test development.

The paper shows the alternatives that exist in the field of material selection, through the comparative evaluation of mechanical and corrosion properties for a range of materials through normalized test procedures and other research activities.
Disposable Wells: A Monobore One Trip Case Study.
Authors: Chapman W.
Published: December 2007

This paper will discuss a Monobore one trip cement through completion system. The system was designed to add artificial lift capabilities and improve safety to short life monobore wells. The disposable well bore concept is gaining popularity in regions worldwide. This paper will also discuss case histories including operation issues and problems and how they were solved.

Operational procedures will be outlined to effectively demonstrate, and discuss the decision making process when determining the most cost effective candidates for this technology.
Evaluating Permanently Installed Fiber-Optic Distributed Temperature Measurements Using Temperature-Step Resolution
Authors: Hadley M. R. , Brown G. A. , Naldrett G.
Published: December 2007

The fiber-optic distributed temperature sensor (DTS) has emerged in recent years as a valuable tool in the oil and gas industry. From intervention services, to permanent wellbore installations, steam-flood, sub-sea installation, and flow assurance, the number and diversity of DTS applications has steadily grown. Supply of DTS instruments, fibers, and services is a lively and growing market which has attracted multiple competing suppliers.

The DTS measures temperature using a length of optical fiber as the sensing element. Each measurement takes the form of a temperature trace or profile comprising samples from regular intervals – usually about 1m – along the entire fiber. Each profile is generated by averaging the weak optical signals that carry the temperature information, over a period of anywhere between a few seconds and a few hours.

While a temperature profile is similar to a temperature log, the simultaneous measurement of all data points and regular repeated measurements give new opportunities for wellbore temperature analysis. Over the last few years, existing techniques have been modified and new ones developed to capitalize on DTS temperature profile measurements. These include measurement of flow rate in producing and injecting wells, and monitoring gas lift valves, as well as monitoring steam flood and SAGD wells. (References [1], [2], [3], [4], [5], [6], [7], [8]).
An ALS Solution to Low-Pressure SAGD
Authors: Wiltse D. J.
Published: December 2007

The trend for SAGD in Canada is towards low pressure steam injection. The primary reasons for this trend are both economical and operational in that low pressure translates to lower operating costs and improved recoveries.1 Low pressure SAGD also requires an artificial lift system (ALS) in order to achieve desired production rates.

This paper will discuss a unique ALS that was specifically developed for the lifting challenges associated with low pressure SAGD - the Hydraulic Gas Pump (HGP). This rodless technology utilizes high pressure gas to positively displace production fluid. At the time of the writing of this abstract, the HGP had passed rigorous lab testing and surpassed all performance expectations in a test well. Furthermore, it is currently being field-tested in a SAGD well in Canada. The paper concludes with the actual HGP field-test performance results from that well.
Initiatives for Improving Oil Recovery at Guntong
Authors: Kueh S. R. M. , Mohamad W. N. W. , Sim C. -H.
Published: December 2007

The Guntong field is one of the largest oil fields in the Malay Basin. With almost twenty years of production history and currently at 80% depletion, Guntong production has been on the decline since the late 90s. Despite the complexities resulting from its multiple stacked reservoirs that are developed by 150 wells, and the challenges of maximizing oil recovery from a mature offshore field, the various oil recovery improvement measures implemented at Guntong have successfully resulted in the addition of almost 80 million barrels of oil to the overall field recovery within the last five years.

This paper is an overview of these initiatives which include workovers to decommingle selected reservoirs and perform acid stimulations, in addition to three infill drilling programs that were conducted within a span of three years. A fourth infill program, requiring a new satellite platform, is scheduled for completion in 2005. Positive results were also achieved by revising the field's reservoir pressure maintenance program along with optimizing reservoir management strategies such as water injection patterns.

The underlying key to the success of these efforts has been the holistic approach in analyzing the field data. A more comprehensive understanding of the reservoir behavior was achieved by integrating production data, geology, reservoir engineering as well as findings from the recent infill programs. A more accurate representation of the reservoir behavior was attained through iterative comparisons between the geologic description updates and the results derived from the reservoir simulation models. Predictions from these models, which were further supported by seismic timelapse and AVO analyses, have led to the successful identification of bypassed oil regions within the field. Moreover, the availability of reliable simulation models was also instrumental in testing out and fine-tuning reservoir management strategies before their implementation.