bluuebunny/crossref_metadata_2025 huggingface dataset:
Use of Fractionation Column in an Offshore Environment
Authors: Li K.J.
Published: December 2007

The Draugen field was the first offshore platform installed in the Mid-Norway offshore acreage. In addition to the challenge of the harsh environment, several innovative designs were implemented in the development.

Due to the unique reservoir fluid composition, low GOR of 55 m3/m3 and 9% propane content, the conventional design of recycling condensate from compression to the crude separators was not very cost effective. By installing a condensate stabilisation column operating at a high-pressure of 24 bara and by minimizing the recycle streams, the installed compression horsepower was reduced by half. Since the start up of the facilities in 1993, the condensate stripper was fully utilized when the production capacity was doubled while still maintaining the single train concept. Recently the operation of the platform was further optimized to enhance the value of the crude and minimizing the discharge of VOC (volatile organic components) from the crude product.

P. 387
An Approach to Real-Time Optimization of the Central Gas Facility at the Prudhoe Bay Field
Authors: Clay Roger M. , Stoisits Richard F. , Pritchett Michael D. , Rood Robert C. , Cologgi John R.
Published: December 2007

As computer costs continue to decline and computer power increases, the technologies of advanced control and real-time optimization become more economical and more easily justified for process plant operation. Upstream oil and gas facilities previously thought not to be candidates for advanced controlor optimization should be given new consideration. The benefits to be realized are many and include reduced operating margins, improved recovery, improved throughput, reduced emissions, reduced utility consumption, and improved safety and operating consistency. As a means to demonstrate the benefits of real-time optimization in an upstream facility, ARCO developed an open-loop prototype optimization tool using existing process models and an expert system operator interface. The north slope Alaska Prudhoe Bay Central Gas Facility was chosen for the application because of existing model development and the potential economic return. In short, the application runs as a process monitor which triggers the model and optimizer when conditions deviate sufficiently from the previous optimization run. Set points are then calculated and displayed for the operator in an advisory manner.

P. 399
Redevelopment and Management of the Magnus Field for Post-Plateau Production
Authors: Day Simon , Griffin Tim , Martins Paul
Published: December 2007

Magnus is the most northerly field in the UK North Sea, with 14 platform and two subsea producers, and 13 injectors of which 8 are subsea. After 12 years of plateau production at 140,000 bopd, the field went on precipitous decline in 1995, with an underlying decline rate of 60% per annum. Although there had been significant preparation and investment for decline, the severity of the well-related problems had not been anticipated. Wells producing over 20,000 bopd fell over in a matter of hours as a result of severe barium sulphate scaling, amongst other factors.

This paper discusses the causes of the severe declines, the increasing evidence of reservoir complexity, and the re-engineering of the reservoir development that equipped the field for post-plateau production. During the first three years of decline, all production wells were either side-tracked or had major interventions to maintain production, as we moved from multi-zone to single zone completions. Crucial to the success of the performance recovery has been the drilling of several injectors, targeted to support specific zones/areas. Facilities upgrades were also made with increased water-handling capacity, gas lift capability, upgraded water injection pumps and a subsea injection manifold all being added.

The subsequent reservoir and well management strategies used are discussed, together with a summary of lessons from the new wells. The main keys to success of the programme are presented, including base production focus and scale management operations. As a result of the re-engineering, the base decline rate has been substantially reduced and manageability has been restored to the field. The lessons learned on Magnus may have relevance for future developments reliant on a small number of wells, particularly if they are subsea.
Effective Evaluation of Fluid Mobility From Stoneley Waves Using Full Biot Model Inversion: Two Case Histories
Authors: Pampuri F. , Rovellini M. , Brie A. , Fukusima T.
Published: December 2007

There are efforts in the oil and gas industry aimed at the evaluation of a continuous permeability profile. Since the introduction of the high-fidelity digital sonic tools, the high quality Stoneley waves available, can be used to determine a continuous fluid mobility profile along the well.

The methodology to obtain an accurate determination of permeability from Stoneley has been the subject of much research. This paper presents the quantitative fluid mobility results obtained from the Stoneley waves with the latest processing techniques in various oil reservoirs. The results were compared and integrated with other mobility measurements such as laboratory core analysis, formation testing and nuclear magnetic resonance logging (NMR), to determine the significance, strength, and weakness of the Stoneley technique. The methodology, is based on inversion of a propagation model that uses the full Biot elasticity theory. This results in a continuous in-situ fluid mobility curve with a quantitative evaluation of its uncertainty.

Two well cases are presented: one from a layered sandstone reservoir drilled with oil based mud, and the second from a thick clastic carbonate reservoir drilled with water based mud. In these examples, the computed Stoneley mobility profile is consistent with the degree of the heterogeneity of the formation. The calculated fluid mobility profiles show a high degree of correlation with core permeability measurements, NMR permeability curves and formation test results.

These examples show that the methodology can be applied with success both in siliciclastic and clastic carbonates with porosity greater than 8-10 %.

The computation is sensitive to the input porosity (effective) and the application to real data shows that the most critical input parameters are those linked to the mud (slowness and attenuation) and to the formation fluid (compressibility). A practical method is proposed to determine these parameters, In these cases the Stoneley mobility curve is comparable to the "absolute" permeability.

The Stoneley fluid mobility curve can provide valuable information both for exploration and production phases. Potential applications complement formation evaluation, optimize production testing programs and strategies, enable early identification of layered reservoirs and static/dynamic reservoir modeling.

P. 401
Mechanical Strength of Reservoir Materials: Key Information for Sand Prediction
Authors: Zhang Jiaxiang , Rai Chandra S. , Sondergeld Carl H.
Published: December 2007

The mechanical strength of a reservoir formation is the most crucial information required for predicting sand production and recommending sand control completion. The only reliable technique, so far, to obtain the formation strength quantitatively is to perform laboratory tests on core samples. The laboratory tests require substantial volumes of cores which, in most cases, are not available. In this study, we present a new method to avoid this restriction. The significance of this approach is its simplicity and efficiency in constructing a reliable mechanical failure envelope. The key results of this study, based on measurements on a variety of sandstones, are:Sandstone formations are characterized by a single normalized failure envelope. This universal curve makes it possible to construct the failure envelope for a sandstone formation from the knowledge of critical pressure.There exists a correlation between the critical pressure and the compressional wave velocity (at equivalent depth of burial).The failure envelope for a sandstone formation can then be Constructed simply from compressional wave velocities. These velocities are generally accessible from conventional logging data.

P. 423
A Coupled Model to Predict Interformation Flow Through an Abandoned Well
Authors: Striz Elise A. , Wiggins Michael L.
Published: December 2007

This paper presents a novel approach to predict flow between two formations coupled by an abandoned well. A steady state abandoned well model is derived analytically and applied using a series of steady state's to create the transient flow response. The model is verified by comparison to the results of a transient analytical interformation well model for a single injector given by Avci. This model is the first to include true pressure losses in the abandoned wellbore calculated from established equations for turbulent or laminar pipe flow, plugs, and a casing perforation. The model can also predict flow behind pipe through an open or plugged annulus or a fracture in the annular plug. Finally, the model is the first to incorporate the effect of pressure variations due to production or injection in the overlying formation on the well flow.

Application of the model in a single phase simulation demonstrates the impact of abandoned well location and condition, rock and fluid properties, and initial pressures and well operations in the coupled formations on the abandoned well flow. Evolving pressure distributions in the coupled formations may move flow up or downhole. Pressure losses in the wellbore or behind pipe through plugs are shown to preclude flow. The model is also applied to a field case to demonstrate its use as a prediction tool for abandoned well transport. As opposed to the limited analytical solutions or complex numerical simulation methods currently available, the new abandoned well model provides a simple means to determine flow for realistic field conditions.

P. 419
Oil/Water Slugging of Horizontal Wells - Symptom, Cause and Design
Authors: Barrett Nathan , King Dave
Published: December 2007

A maturing BP oilfield called Wytch Farm has recently experienced operating problems with its ESP wells. Large fluctuations had been seen in flowrate, pressure and supply current. The fluctuations were recorded for several different flowrates, before being analysed. The analysis of the data gave a suspicion that these wells were slugging in the wellbore before the pump inlet. However only oil and water are known to exist in the wellbore in this particular field and this type of behaviour had never been seen before in this oilfield.

Discussion about the mechanisms of oil-water slugging, and also why these wells have recently started to slug are included.

Transient analysis of the well using OLGA (ref 1.) gave a good representation of the wellbore and a degree of confidence that we could predict the flow pattern. Further analysis led to a better understanding of the mechanisms Causing these operational issues. The end result is that recommendations can be made for future wells and indeed the same analysis is recommended before they are completed to avoid this unusual problem in the future.

P. 461
A Simplified Model for Oil-Water Flow in Vertical and Deviated Wellbores
Authors: Hasan A.R. , Kabir C.S.
Published: December 2007

This paper presents the results of an experimental study and a semitheoretical analysis of two-phase oil-water flow in vertical and deviated systerns. The study focuses on water- dominated flow regimes, where the patterns may be termed as bubbly flow, pseudoslug flow, and churn flow. A drift-flux approach is taken to analyze the flow behavior of oil-water systems. For the three flow regimes investigated, the drift flux of the lighter oil phase is found to be dependent on its in-situ volume-fraction in addition to the terminal bubble-rise velocity. This behavior is in contrast to the gas-liquid flow, where the drift flux has often been found to equal to the bubble-rise velocity. For flow in both vertical and deviated pipes, we were able to develop a single expression for the drift flux, Uow, resulting in a single equation for the in-situ oil fraction, fo, for the three flow regimes studied. We correlated f0 with the oil superficial velocity, vos, and the terminal rise velocity, voo using the expression, fo=. In a deviated pipe, the terminal rise velocity, voo is correlated with that in a vertical pipe by.

The performance of the proposed method in estimating fo is in good agreement with our measurements. Published data further augment the approach presented here.

P. 493
Effective Reservoir Simulation of the McKee Field, New Zealand
Authors: Wadsley A. W. , Adams M. R. , Stoltz L. R. , Jones M. S.
Published: December 2007

The McKee Field was discovered onshore New Zealand in 1979 and brought to commercial production during 1984. Beginning with the early stages of development planning, each stage of the field's life has been actively guided by reservoir simulation. An early pre-development model was built in 1983, and full field simulation has been carried out, and routinely updated since 1986.

A review of the effectiveness of reservoir simulation as an ongoing planning and management tool for the McKee Field has been conducted. It is shown that reservoir simulation, even at the earliest stages, can act as an accurate model for determining optimum recovery processes and development strategies. Models must be continuously updated and refined to reflect the current best knowledge of the reservoir in order to remain effective at locating infill or re-completion candidate wells and at addressing the changing reservoir management objectives of the day. The ability of the model to accurately predict future field performance, is shown to be directly related to how well the simulation model represents reservoir geology, and structure, and the consequent relative ease with which a history match has been obtained.

The simulation technology applied has evolved, in order to accurately represent the improving state of reservoir knowledge with time, from conventional cartesian gridding with vertical faults used in 1983 and 1986, through corner-point geometry applied in 1988, simple polygonal gridding first applied to full-field modeling in 1991, to the complex polygonal full field model with explicit over-thrust and multiple back-thrust fault matching in use today.

The current simulation model is both a dynamic fluid-flow model and a detailed 3-D geological model of the reservoir. It includes a comprehensive representation of stratigraphy, permeability anisotropy, and all mapped faults with as-mapped dips and strikes. This model is currently used to plan infill drilling, water-flood, for appraising tertiary gas flood and WAG, and for managing aspects of production optimization.
A New System To Enhance Production of Mature Wells
Authors: DeGhetto G. , Paone F. , Nielsen K.L. , Villa M.
Published: December 2007

The paper presents, focusing on the field experience, an innovative system aimed at increasing the production rate of mature wells that exhibit low well head flowing pressure.

The system is essentially constituted by a normal centrifugal pump, fed by live oil coming from an existing separator, which activates a multiphase ejector that "sucks" the mature well/wells. The separator can be fed by other wells or by the same boosted well in a short circuit way.

The innovative system was eventually applied in field after a four years R&D project.

The field results are extremely good showing an increase of the oil rate of one well by more than five times: production before was 0 - 200 bopd (fluctuating), production after was 1000 bopd stabilized, with a decrease of the flowing well head pressure of 200 psi.

Costs: CAPEX 300.000 $, OPEX 1$/bbl, pay out time about 1 month.

The paper will report and analyze the results of this application and discuss the potential use of the system in various scenarios for boosting low well head pressure oil wells.

P. 501
Emulsification of Production Fluids in the Choke Valve
Authors: van der Zande M.J. , Muntinga J.H. , van den Broek W.M.G.T.
Published: December 2007

For oil production under high water cut conditions the efforts needed for de-oiling of the production water are mainly determined by the oil-droplet-size distribution of this water. This distribution is predominantly the result of droplet breakup in the choke valve. To determine the effect of the choke valve on the droplet-size distribution, we have conducted laboratory experiments in which we used a circular orifice in a circular pipe. With the help of theory on droplet break-up in turbulent flow and with knowledge of the flow field inside an orifice, a prediction of the distribution after break-up can be made. It is shown that the droplets increase in size with increasing oil viscosity and furthermore it appears that, for the description of the break-up process, the distribution of the turbulence over the orifice zone is an important factor.

P. 525
Applying Log-Constrained Seismic Inversion Technique To Optimize the Development of an Offshore Marginal Oil Field
Authors: Meifang Tang , Shuling Sui , Jun Wang , Jiquan Yin
Published: December 2007

Chengdao Oilfields is located in Bohai Bay of East China. The Oil-bearing sandstones are fluvial sediments of Tertiary upper Guantao Member. The sand bodies change rapidly both in thickness and lithology. It results in quite different productivity between the wells. Development of the oilfield needs high investment with low economic efficiency, and will be full of risks.

In order to predict the distribution of the sandbodies and its petrophysical properties to optimize the well locations, a stratigraphic research using log-constrained seismic inversion technique was conducted. By means of improving the processing methods, the stratigraphic wave impedance data with high resolution and accuracy were obtained. According to the relationship between the wave impedance data and the reservoir properties, the lateral changes of the reservoir and it's petrophysical properties were disclosed.

Based on this results, 86 wells have been successfully drilled in areas with thick reservoir. Comparing with expected number and thickness of the layers in individual wells, the well numbers with errors less than 20% are 74 (86%) and 67 (78%) respectively. It makes the previous marginal oilfield to be a cost effective recoverable oilfield.

This paper presents the research concerned and it's results.

P. 557
Coupling Financial Profit Indicators to a Net Cash Flow Model for Production Sharing Contracts
Authors: Thompson Robert S. , Wright John D.
Published: December 2007

With the increased emphasis on shareholder earnings and financial "profit," project evaluators are facing more questions about the impact of projects on financial net income. This paper demonstrates a method of coupling traditional project net cash flow analysis to incremental project pro forma financial statements for a production sharing contract. The coupling of a project net cash flow model with pro forma financial profit indicators provides an additional measure of profitability and information that may enhance project selection. In production sharing contracts, the cost recovery feature may enhance incremental project financial net income in early project years when intangible expenditures are significant.

P. 567
An Innovative Technique of Obtaining Project Financing for the Equity Share of a Developing Country's National Oil Company
Authors: Schaaf Robert P.
Published: December 2007

It is not uncommon for the National Oil Company (NOC) of a developing country to encounter difficulties in obtaining project financing. Due to the instability of their economies, credit is often reduced or withdrawn. If granted, credit is typically underwritten by proven reserves. However, the funds flow problem becomes acute as a larger and larger portion of existing reserves is provided to collateralize debt. This dilemma might be circumvented by switching to financing structures derived through the use of the NOC's share of existing or proposed surface facilities as debt security.

While the concept seems simple in theory, the application of potential components of this type of financing can prove to be quite complex. Various elements must be considered in the equation determining the optimal borrowing terms. The inability to resolve or mitigate certain issues - political instability, facility life and alternative uses, operational hazards, existing production questions, taxes, and de facto partial ownership of assets by a financial institution - is the primary reason the technique has not been widely developed and utilized.

In order for favorably resolved issues to prove useful, they need to be presented in a manner acceptable to the financial institutions. Additionally, requests for financing must fit within the funding parameters of the chosen financing source. Therefore developing a loan package that is palatable to the large financing syndicates will often prove a rigorous and daunting task. However, executed properly, this effort can release previously unavailable funds.
The Application of Novel Wax Divertor Technology to Allow Successful Scale Inhibitor Squeeze Treatment into a Sub Sea Horizontal Well, North Sea Basin
Authors: Jordan M.M. , Edgerton M.C. , Cole-Hamilton J. , Mackin K.
Published: December 2007

This paper presents field results from two scale squeeze treatments carried out on the same sub sea horizontal well from a field in the North Sea, The initial squeeze was a bullhead application of phosphonate scale inhibitor to control a sulphate scale problem in a horizontal well. Ten months after the initial treatment a second bullhead squeeze treatment was applied in two stages. This utilised a thermally degraded pelted wax divertor to temporally impair injectivity in the heel region of the horizontal well thus allowing propagation of the second stage of the squeeze treatment into the mid section of the horizontal well.

This paper will show the significance of production logging tool data toevaluate the location of deposited scale and water production prior to a squeeze treatment. Such data was used to design a novel two stage squeeze treatment in which an initial squeeze slug was applied to the heel region followed by application of a pelted thermally degraded wax divertor to prevent further loss of scale inhibitor to the heal region. The action of the divertor allowed a second scale inhibitor to the heel region. The action of the wax divertor allowed a second scale inhibitor slug to be placed further along the horizontal section of the well. Details of divertor selection and the squeeze design strategy implemented in this squeeze treatment will be presented. During the field treatment, physical (downhole pressure and temperature) data and chemical (non-radioactive tracers, inhibitor and ion Concentrations) data were recorded. This data will be used to indicate the success of diversion treatment by comparison with the first squeeze applied to the same well ten months previously.

This is the first successful application of a thermally degraded wax divertor to a subsea horizontal well in the North Sea basin. The well was successfully treated with no process up set during flowback and no decline in well production whilst allowing the well bore to be protected from continued sulphate scale formation. This paper clearly shows that with the correct selection of both scale inhibitor, divertor agent together with the utilisation of all available information relating to the reservoir. It is possible to squeeze scale inhibitors into sub-sea horizontal wells without the need for expensive coiled tubing intervention from a diving support vessel. This technology is not limited to horizontal wells and could also be applied tovertical wells with significant cross flow problems to aid in selective placement during scale inhibitor squeezing.

P. 633
A Wellbore Model for Predicting Aspholtene Plugging
Authors: Kocabas I. , Islam M.R.
Published: December 2007

Asphaltene precipitation can have profound effects on oil production during miscible flooding, heavy oil recovery, or even primary depletion. Even though asphaltene precipitation has been known to have strong effects on permeability reduction, quantitative analysis of the process has been started only recently. This paper extends the previous work to consolidate some of the hypotheses and develops a comprehensive wellbore model. The wellbore model couples the asphaltene adsorption model with a series of phenomenological models that are independently validated with either experimental or field data. These models are incorporated into the mathematical model, for a linear as well as radial system. The radial model is particularly useful for simulating asphaltene transport and deposition near the wellbore because of the continuously changing speed for this case. Intially, the governing equations were solved analytically in order to observe the role of some of the parameters independently. Following this, a series of numerical runs was conducted to observe the role of various governing parameters on wellbore parameters under more realistic representation.

Experimentally, the deposition was found to be a function of permeability, flow rate and concentration. Two distinct mechanisms were identified, namely, deposition and adsorption. Deposition could be explained in terms of trapping and mechanical plugging. The model builds on the two mechanisms described above. The coupled mathematical model predicts permeability damage due to mechanical trapping and adsorption accurately, as evidenced when compared with experimental results. Three different plugging regimes were identified and were verified with the numerical model. A series of predictive runs further clarified the transition between different flow regimes.

This paper offers readers with the first wellbore model that uses irreversible thermodynamics to model adsorption and desorption and couples it with a comprehensive mechanical trapping model. The simulator applies to all reservoirs with asphaltene problems.

P. 671
Problem Diagnosis, Treatment Design, and Implementation Process Improves Waterflood Conformance
Authors: Love Tracy , McCarty Andrew , Miller Matthew J. , Semmelbeck Mark
Published: December 2007

The Eunice Monument South Unit (EMSU) produces from the Grayburg formation in southeast New Mexico. The unit has higher than expected water production and lower than expected oil production since a waterflood was installed in 1986; poor vertical flood conformance is to blame. A major project was initiated in 1996 to characterize the reservoir and improve the flood conformance where possible.

Reservoir characterization included mapping high permeability streaks, material balance, and percent pore volume swept calculations. Two techniques, production data diagnostics and injection well diagnostics, were then applied to characterize the performance of individual wells. The subsets of wells that were identified as underperforming by each method were compared and a focus area was selected to pilot test a waterflood conformance correction program. Primary problems discovered included water cycling through high- permeability streaks, water injection into the gas cap, and wellbore zonal isolation problems.

The waterflood conformance correction program comprises problem diagnosis, treatment selection and design, treatment execution, and treatment evaluation. Several different treatments (cement squeeze, near-wellbore gel treatment, and deep-penetrating gel treatment) were executed depending on the problem encountered. This program has been implemented on 29 wells in EMSU. Production response to the treatments is discussed.

P. 689
Using Radio Frequency Identification Electronic Chips to Effectively Control the Elements of the Drillstring
Authors: Sampaio J.H.B. , Placido J.C.R. , Ferreira S.N.
Published: December 2007

The identification of drillstring elements (in particular drillpipes) is currently performed in PETROBRAS using serial numbers imprinted somewhere on the body of the element. A procedure will be set up to establish effective control of these elements, such as accumulated cycles, accumulated footage, inspection reports and, particularly, accumulated fatigue. It is necessary to track each element along all campaigns in which it takes part by identifying its position on the drillstring, registering the mechanical parameters it is submitted, and registering the mechanical conditions of the borehole. Using the traditional imprinted serial number, it is difficult (or almost impossible) to keep a reliable log of each drillstring element in the rig site. The use of electronic chips attached to the body of these elements allows a fast, efficient, and reliable identification of each element through a unique key number. A manual reader is used to scan the chip and send the information to a local database at the rig site. The drilling parameters are obtained in real time through sensors distributed along the rig and sent to the database. At given time intervals, these data are used to calculate the fatigue each element was exposed to and accumulate the data in the database. A suitable mathematical model then is used for the fatigue calculation. Before being connected to the drillstring, each element is checked for accumulated fatigue and is accepted or rejected depending on the expected fatigue it will be exposed to in the campaign. Integrated databases on the operative units control the stock, inspection reports, supply, purchase, and discard of the drilling elements. Elements used before the implementation of the system are considered dummy elements with respect to the accumulated fatigue and are treated as usual. New elements are tracked since the first drilling operation. A period of several years (the average life span of the elements) is expected until all old, untracked elements are replaced by new, tracked elements. Among several benefits, this procedure is expected to significantly decrease drillstring failure due to mechanical fatigue, with consequent associated cost savings.

P. 619
Torsional Resonance of Drill Collars with PDC Bits in Hard Rock
Authors: Warren T.M. , Oster J.H.
Published: December 2007

Formations encountered while drilling oil and gas wells are not homogeneous. This requires drill hits to be capable of drilling the most difficult rocks in the interval rather than the "average" rock and can result in a significant penetration rate penalty for cases where a few hard streaks preclude the use of PDC bits. Bit manufactures are actively trying to improve materials and bit designs to provide more robust bits, but in many cases it appears that some type of drillstring vibration limits the use of PDC bits in these hard streaks. Extensive data from drilling tests conducted at Amoco's Catoosa test facility indicate that PDC bits are damaged very rapidly when they encounter certain hard rocks. The visual appearance of the damage suggests some type of vibration damage, but the normal cures for bit whirl and drillstring stick/slip do not seem to be very helpful. The analysis of nineteen wells where a downhole vibration sensor was run and PDC bits encountered severe damage indicates that torsional resonance of the drill collars could result in backward rotation of the bits. The observed vibration has been known to exist (in a theoretical sense), but is not recognized as a significant cause of PDC bit failure. The Catoosa drilling data shows conclusively that a wide range of PDC bits sustain this type of vibration when they drill hard rocks. Laboratory tests demonstrate that reverse rotation of PDC bits result in catastrophic Cutter failure. The evidence collected so far suggests that reverse rotation due to torsional vibration is probably the cause of the rapid damage in certain hard rocks, but this postulation has not been proven because the sensor used in the tests was not adequately sensitive to say positively that the bit rotates backwards.

P. 625
Using downhole dynamics to better understand the drilling process with positive displacement motors and PDC bits
Authors: LAMINE E. , LESEULTRE A. , ROBERTS D. , WALKER C. , JONSSON A.
Published: December 2007

Downhole dynamics is now better understood through the application of downhole instrumentation. Vibration measurements at the bit have given us a precise understanding of PDC bit behavior from stick-slip to backwards whirl with pendulum and packed hole rotary assemblies.

Many PDC bits are however run on downhole motors for directional and performance reasons prompting testing to be done with an instrumented bit below such motors. This paper will present how PDC bits behaved below low speed and high speed motors. Measurements were taken while drilling both in rotary and sliding modes and also with straight and bent housing motors to obtain results over a wide spectrum of motor applications. Besides the effects on bit performance this paper will present, for the first time, the actual characteristics of a positive displacement motor operating in a downhole environment. The subsequent integration of bit and motor design will lead to the development of a more efficient and reliable drilling system. The PDC bits tested incorporated a new three dimensional design so as to minimize downhole vibrations.
Modelling of Transient Two-Phase Flow Operations and Offshore Pigging
Authors: Lima P.C.R. , Yeung H.
Published: December 2007

Transient gas-liquid processes and operations involving pigging has been successfully applied in hard environments offshore Brazil for assure an efficient oil and gas flow.

These pigging operations are: wax control in deep water multiphase flowlines, water and condensate removal from complex offshore pipeline systems and the use of pigging inside the well as an artificial lift system. Despite of the tremendous success of these operations in the last years, they were performed just based on experience. A new subsea boosting system using gas and pig to transport the accumulated oil in the flowline is also proposed and evaluate. This paper describes some of these operations and a new model to simulate them.

A two-fluid model was developed to determine the transient behaviour of fluids during these operations. The derived one- dimensional set of equations for each flow pattern describe the flow of fluids in all regions. Semi-implicit finite difference schemes were used to solve the initial and boundary value problem for each phase of the pigging process: gas/pig injection, gas shut-in, slug production and gas flow out of the system. A significant improvement upon previous work makes unnecessary to track the position of the slug front. Lab and field data are compared to the results from the theoretical model.

P. 701
Field Testing and Commercial Application of High-Efficiency Nonpolymeric Gas Hydrate Inhibitor in Offshore Platforms
Authors: Pakulski Marek , Pukop Gabriel , Mitchell Caesar
Published: December 2007

A nonpolymeric gas hydrate inhibitor has been successfully field tested on a platform containing ten gas lift injection wells in an offshore location on Gulf of Paria near Trinidad. Several wells are connected to a common 2" pipeline with a typical pressure in the system of 1800-1900 psi. Gas decompression at the wellhead results in lowering the temperature below freezing and creates favorable conditions for hydrate formation. Prior to the test and in spite of using methanol, the field operator, Trinmar Ltd. experienced frequent flow disruptions due to gas hydrate formation. The inhibitor formulated in hydrocarbon solvent solution was injected into a gas line at initial concentration 1/2 of the previous methanol usage and the dosage concentration was gradually lowered to 1/15 of methanol until hydrate formation was observed. The hydrate disappeared upon inhibitor concentration increase to 1/10 of methanol. The treatment with the gas hydrate inhibitor was finally optimized at 1/8 of the former methanol usage. The entire field has been converted from methanol hydrates protection to the inhibitor following the successful test and the treatment has been running since late 1996 without any problems. No product accumulation in the system (gunking, agglomerating, etc.) has been observed. This is a result of the fact that the neat inhibitor is a liquid oligomer. Trinmar realized large direct and indirect monetary gains due to this new treatment.

P. 711
Characterization of a Vertically Compartmentalized Reservoir in a Supergiant Field, Burgan Formation, Greater Burgan Field, Kuwait; Part 2: Evolving Concepts of Reservoir Performance
Authors: Carr Brian S. , Kirby Robert H. , Al-Humoud Jamal , Al-Matar Dawood , Naser Waleed , Safar Ahmed
Published: December 2007

This is the second of two papers which describe a comprehensive multi-discipline effort toward characterizing the Burgan formation of Greater Burgan field in Kuwait, as a necessary precursor toward effective reservoir management. This level of foundation-building work toward characterizing Burgan stratigraphy, rock properties, fluid properties, and fluid distributions had not previously been undertaken during the prior fifty years of reservoir exploitation. However, during the late l98Os, water production became an issue. Then, as a result of the sabotage of Greater Burgan field during the Gulf War, the reservoir experienced a period of uncontrolled production during the blowouts of 1991. Subsequently, a concerted effort has been made to understand and characterize this huge reservoir.

This paper, Part 2, describes the evaluation of petrophysical data and heavy oil (tar) distributions, and the resulting understanding of movable oil within the formation. The paper also addresses issues regarding the integrity of historical production data, and the resulting approach toward predicting field performance. Lessons learned are discussed, including the importance of a strong data foundation, and the importance of ground truthing history-match adjustments. The planned way forward to a better understanding of this supergiant reservoir is also discussed; the way forward deemphasizes history-matching. (The focus of this paper is primarily the Burgan formation, which is the dominant producing horizon of Greater Burgan field. The Wara, Mauddud, Minagish, and Marrat formations also contribute to field production. Part 1 of this two-paper series describes the stratigraphy and water encroachment of the Burgan formation.)

P. 521
Characterizing the Greater Burgan Field Using Geochemical and Other Field Data
Authors: Kaufman R.L. , Kabir C.S. , Abdul-Rahman B. , Quttainah R. , Dashti H. , Pederson J.M. , Moon M.S.
Published: December 2007

This paper describes recent results from an ongoing geochemical study of the supergiant Greater Burgan field, Kuwait. Oil occurs in a number of vertically separated reservoirs including the Cretaceous Third Burgan, Fourth Burgan, Mauddud, and Wara. The Third and Fourth Burgan sands are the most important producing reservoirs. Over 100 oils representing all major producing reservoirs have been analyzed using oil fingerprinting as the principal method, but also supported by gravity and sulfur measurements.

From a reservoir management perspective, an important feature of the field is the approximately 1,200-ft long hydrocarbon column which extends across the Burgan reservoirs. Oil compositions vary with depth in this thick oil column. For example, oil gravity varies in a nonlinear fashion from about 10 API near the oil-water contact to about 39 API at the shallowest Wara reservoir. This gravity-depth relationship makes identification of reservoir compartments solely from fluid property data difficult. Including oil geochemistry in the traditional mix of PVT and production logging data improves the understanding of compartmentalization and fluid flow in the reservoir, both in a vertical and lateral sense.

The composition of reservoir fluids is controlled by a number of geological and physical processes. We attempted to identify unique sets of geochemical parameters that were sensitive to specific oil alteration processes. One set of geochemical properties correlated strongly with gravity and is therefore related to the gravity-segregation process. A second set of parameters showed essentially no correlation with gravity or depth but established unique oil fingerprints for most of the major producing reservoirs and identified a number of different oil groups within the Burgan and Wara reservoirs. We interpret the presence of these oil groups to indicate reservoir compartments owing to laterally continuous shales and faults, which act as seals on a geologic time frame. Compositional differences between groups of oils arise from the reservoir filling process. A third set of parameters correlate with water washing and/or biodegradation processes, indicating oil alteration during production. We are investigating these parameters to determine if they can identify production-time-frame barriers. The geochemical data were integrated with PVT-data for better understanding of the fluid distribution.

P. 533
Application of Petrophysically Derived "Flow Facies" for Reservoir Characterization and Simulation: Wara Reservoir, Greater Burgan Field
Authors: Moon Mark S. , Pederson John M. , Osmon Kamal , Al-Saied Mariam , Al-Sabea Salem H. , Al-Shammari Hana'a
Published: December 2007

In fluvially dornihated delta plain reservoirs, such as the Wara formation in the Greater Burgan Field, characterizing a reservoir's flow properties accurately is essential in developing a sound reservoir model. This is easier said than done. Typically, lithofacies identified in cores are correlated to multiple log suite characteristics. These are then used to help define simulation flow properties in wells. In Greater Burgan, with over fifty years of production, much of the field development occurred before modern diagnostic logging tools became available. Therefore, direct correlation of core lithologies and corresponding lithofacies description to multi- log character is not possible in the majority of wells.

Relationships discovered between shale volume (VSH) ranges and effective porosity to permeability transforms allowed us to apply unique rock properties to flow units or "facies" defmed by the VSH-porosity ranges. These flow facies eliminated the difficult task of trying to predict changing lithologies and lithofacies in wells with limited log traces and no core.

P. 547
Managing Wet/Dry Crude Production with Reservoir Simulation in the Greater Burgan Field, Kuwait
Authors: Harris Dan E. , Yardumian Hrant E. , Al-Naqi Meqdad A.
Published: December 2007

We designed, coded, and successfully installed wet/dry producing rules in an in-house multipurpose reservoir simulator. This paper discusses how we are using this feature to manage the development of the Greater Burgan Field.

Wet/dry reservoir simulation played an important role in deciding the future production rate of Greater Burgan. We studied plateau rates ranging from 1.25 to 2.5 MMBOPD to see which production rates will or (more importantly) will not require facility upgrades for many years. For development scenarios that require upgrades, wet/dry was a key contributor for assisting with facility sizing and timing. The wet/dry producing rules demonstrated that substantial production increases were sustainable by segregating commingled flowlines. Wet/dry also indicated whether wet or dry production strategies were possible at planned development rates. Management selected a future rate of 1.7 MMBOPD as a result of this work.
A Short-Time Model to Correct Environmental Effects in PNC Logging
Authors: Harris C.K. , Kimminau S.J.
Published: December 2007

Current Pulsed Neutron Capture (PNC) logs used for the location of unswept and bypassed hydrocarbons rely upon empirical environmental correction methods, which limit their application in low-contrast situations. A physical, analytical model is derived and applied to the problem of the ultimate sensitivity possible for hydrocarbon~water differentiation in timelapse mode. It appears that significantly better borehole effect correction can be possible compared to current methods. For classical low-contrast situations involving low porosities and low salinity water drives, it should be possible to extend the usefulness of the PNC method in differentiating oil and gas from fresh water in timelapse mode.

P. 581
Progress and Future of Pulsed Neutron Technology in Oil Field Management
Authors: Badruzzaman A. , Neuman C. H. , Adeyemo A. O. , Dodman C. A. , Skillin R. H. , Zalan T. A. , Badruzzaman T. , Bilodeau B. J. , Logan J. P. , Limon M. A. , Belanger D. L. , Featherstone C. J. , Nguyen P. T.
Published: December 2007

The recent advances in pulsed-neutron technology for oil field applications are discussed. The progress includes applying the technology to a number of formation evaluation and production logging problems, use of Monte Carlo modeling to understand response in complex field-like conditions, and development of interpretation algorithms in non-calibrated conditions. The remaining challenges in current applications and a number of emerging or proposed measurements using the technology are described.
A New Water-Flow Velocity Log for Use in Conformance Evaluation
Authors: Simpson Gary A. , Jacobson Larry A. , Ethridge Ray
Published: December 2007

The conformance of unwanted water in producing wells is becoming increasingly important because of costs associated with separation and disposal. A new water-velocity log based on oxygen-activation measurements was recently introduced. The measurements are made with a new small-diameter (1-11/16-in., 43 mm) tool whose design was directed towards enhanced evaluation of water conformance.

This paper discusses the laboratory measurements that characterize the logging technique. Field logs from the Gulf of Mexico region illustrate various water-flow regimes that can be identified with the technique. An interesting example of simultaneous upward and downward flow demonstrates the utility of the tool.

The tool uses two spectral gamma ray detectors and a pulsed neutron generator with a special timing sequence designed to emphasize activation measurements. Spectral measurements enhance velocity estimates by allowing gamma rays from oxygen activation to be distinguished from those arising from iron activation, silicon activation, and natural activity. Furthermore, spectral measurements permit analysis of Compton scattering to indicate whether water is flowing inside or outside the casing.

Water velocity is determined by two methods:

Use of a count-rate ratio from the two spectral gamma detectors, which provides a continuous log but requires well-calibrated detectors. Use of an impulse/shutdown sequence, which is performed while the tool is stationary and which is calibration independent.

The latter method is preferred. Velocity measurements can be performed at water flow rates from 3 to 50 ft/min when detectors are spaced 3 and 4 ft from the neutron generator. With additional longer-spaced natural gamma ray measurements, the range can be expanded to approximately 00 ft/min with the impulse/shutdown method.

Modular design allows the tool to be configured with additional gamma detectors placed both uphole and downhole relative to the neutron generator. This configuration allows the tool to measure simultaneous upward and downward water flow with the impulse/shutdown method. Additionally, modular design permits the tool to be combined with production logging sensors, such as spinner, temperature, density, and hold-up tools, for more comprehensive flow analysis.