bluuebunny/crossref_metadata_2025 huggingface dataset:
Enhanced Scale Inhibitor Placement by Gravity Slumping In High-Permeability Horizontal Wells - Draugen Field, North Sea
Authors: Wahid F. , Graham G. M. , Jordan M. , Oliphant D.
Published: December 2007

This paper examines the impact on scale squeeze life of water/scale inhibitor re-distribution during extended shut in periods for bullhead scale treatment in a high permeability reservoir. The Eclipse 100 reservoir simulator was used to examine water re-distribution (gravity slumping) during extended shut in periods for horizontal wells in the Draugen reservoir. The work shows that in certain cases involving long horizontal wells (>1000 ft) in high permeability sands (3-5D) with low vertical/horizontal permeability contrasts, extensive water re-distribution can occur during extended shut-in periods owing to density differences between the injected (aqueous) fluids and the formation fluids. Full field reservoir modelling was then carried out to identify candidate wells within the Draugen field which offered greatest potential for improved chemical placement based on these findings. Near wellbore placement modelling was then conducted to optimize squeeze return lifetimes using gravity re-distribution to improve placement deeper (lower) in the reservoir vs. convention scale squeeze design methods such as larger overflush.

The work demonstrates that for selected cases, gravity re-distribution can be used to improve placement deeper (lower) in the near wellbore area. The modeling work also identifies limitations with the simple "radial" near wellbore models for such cases and identifies those wells in the Draugen field which would benefit from such treatments. An added benefit for low water cut wells was the potential to minimise post treatment lift issues associated with the injection of high volumes of water into the near wellbore for aqueous squeeze treatments, by allowing the injected aqueous treatment to sink away from the near wellbore area. New field treatments have therefore been designed based on the work described. The economic impact of the extended shut in times vs. improved squeeze treatments and deferred oil costs for this field case are also discussed following the field applications.
A Complete Theory of Scale-Inhibitor Transport and Adsorption/Desorption in Squeeze Treatments
Authors: Sorbie K. S. , Gdanski R. D.
Published: December 2007

Software tools for designing downhole scale inhibitor (SI) squeeze treatments are widely available and have been successfully applied in thousands of wells worldwide. Many SPE papers have been published describing such squeeze design case studies from the conceptual modelled design, to implementation and post treatment analysis. These models are based on the fundamental transport equations for the SI in the near well formation. These equations must also include a model describing the SI/rock interaction, regardless of whether it occurs by an adsorption/desorption or by a precipitation (phase separation) mechanism. A number of papers have appeared in the literature on these fundamental equations and on the analytical and numerical models based on them.

In this paper, we present a re-evaluation of the equations that have been proposed to model SI transport and adsorption in porous media. We have analysed the various approaches in terms of two basic aspects: (a) the mathematical structure of the various equations used to describe transport; and (b) the surface chemistry assumptions and models used to describe the SI/rock retention mechanism, particularly by adsorption. We specifically focus on comparing and reconciling our own (Heriot-Watt U. and Halliburton) respective approaches, which have been developed over the last few years.
Application of Scale Dissolver and Inhibitor Squeeze Through the Gas Lift Line in a Subsea Field
Authors: Kelly M. N. , James J. S. , Frigo D. M. , Driessen D. W. , Waldie A. D.
Published: December 2007

The Kestrel field is an 8-km sub-sea tie-back to the Tern platform in the Northern North Sea, and consists of two gas-lifted (GL) producers supported by a single injection well. Seawater broke through at P1 in the first half of 2004, and after several months at low seawater fractions a very rapid decline observed in the downhole pressure gauge was inferred to be caused by BaSO4 scale. Although the scaling tendency was predicted to be relatively low in this Brent-type reservoir ([Ba2+] < 30 mg/l in the formation water), other flow assurance causes, including sand production and liner collapse, were deemed much less likely.

The most cost-effective manner to confirm the inference of scale, as well as to recover lost productivity and prevent further deterioration in P1, was deemed to be a scale dissolver treatment deployed through the sub-sea GL line, via the crossover valve and into the well, followed by an inhibitor squeeze, similarly deployed. The rationale was that even partial recovery of productivity by the dissolver and/or arrest of further decline by the squeeze should confirm scale as the culprit. Although successful GL-line-deployed inhibitor squeeze had been reported earlier using a non-aqueous package, this was the first using conventional aqueous chemicals, as well as being the first deployed together with a scale solvent. Deployment of a solvent along the methanol line, reported elsewhere, was precluded in Kestrel by the small umbilical diameter and materials constraints. The main challenges in both Kestrel treatments included control of the fluid fronts, compatibility with the materials in the GL line, and prevention of hydrate formation, both at the start of the treatment and upon re-commencement of gas-lift injection.

We report how these challenges were met, and how GL-deployed treatments recovered productivity on P1 and demonstrated that scaling in the field could be managed in this manner in the future.
Evaluation of Inorganic Scale Deposition in an Unconsolidated Reservoir by Numerical Simulation
Authors: Daher J. S. , Gomes J. A. T. , Rosário F. F. , Bezerra M. C. , Mackay E. J. , Sorbie K. S.
Published: December 2007

A good understanding of in situ brine mixing is important for offshore deep water fields under water injection. Incompatibility between the injection and formation waters may result in inorganic scale precipitation in the reservoir, in the well tubing and gravel pack, in flow lines and in surface equipment. In this work, we have used reservoir simulation to model injection brine/formation brine mixing and its effect on reservoir scaling. The objective of this work is to predict in situ brine mixing and its consequences using a simulator that models the kinetics of the scaling reactions. A semi-compositional simulator was used to model the barite deposition reaction which may occur in the reservoir and in the well. In this approach, we take into account the kinetics of the reactions, rather than assuming the traditional (equilibrium) thermodynamic model. Detailed near-well modelling using local grid refinement (LGR) was carried out to forecast of the level of barite precipitation which occurred in the gravel-pack and the consequent production losses. We have also modeled scale inhibitor treatments of the scaling well and a simplified "scale removal" treatment, again including additional preventive scale inhibitor squeeze treatments.
Options and Limitations of Formation Evaluation through Casing for Casing-While-Drilling Operations in South Texas
Authors: May D. H. , Caron S.
Published: December 2007

The drilling of gas reservoirs like the Vicksburg and Wilcox, in southern Texas poses many technical difficulties. Among these challenges are high temperatures, over pressured zones and depleted zones.

In order to minimize the drilling risk, drill faster, and reduce the completion cost, many operators have turned to casing while drilling. While the overall risk and drilling cost may be reduced, the opportunity to adequately evaluate the various producing horizons with conventional logging tools is lost. Because of inadequate formation evaluation, zones that are water-producing, depleted, or tight may be completed, resulting in added stimulation and completion costs that can offset any cost savings achieved while drilling.

This paper will discuss various options and limitations for formation evaluation through-casing, by comparing the results of through-casing evaluation with a petrophysical analysis derived from open-hole logs.

The options will include pulsed-neutron measurements, through-casing acoustic measurements, and cased-hole resistivity.
Optimistic Approach to Control Arc Stability in Unconsolidated Sands by Downhole Emulsification
Authors: Desouky S.
Published: December 2007

Production of heavy oils from Egyptian unconsolidated sand reservoirs causes sand production. It was proposed to use the Downhole Emulsification technique to control arc stability in the unconsolidated sand formations. The Downhole Emulsification was proved to be a significantly effective operational technique to handle sand production. The process involves the injection of an aqueous non-ionic surfactant solution into the well-bore to convert the water/oil emulsion to oil/water emulsion retaining at the same time sand within the oil phase.

In the present work, a physical model was designed to simulate the sand production process. Then the rheological properties of oil/water and water/oil emulsions containing sand were measured at the reservoir conditions. The stability of the emulsions and sand accumulation rate were also examined under dynamic conditions. Sensitivies to water/oil ratios, surfactant concentrations, sand production rates, and different crude oils were performed in this study. Results were consequently used to optimize the composition of the aqueous surfactant solution, flow rate and settling velocity that guarantee a successful Downhole Emulsification process to keep sand in oil phase, hence control arc stability. The paper presents three case histories indicating very promising results.
The Effect of Fracture Relative Permeabilities and Capillary Pressures on the Numerical Simulation of Naturally Fractured Reservoirs
Authors: de la Porte J. J. , Kossack C. A. , Zimmerman R. W.
Published: December 2007

Engineers using numerical reservoir simulators to model fractured reservoirs typically have used straight-line (corner-to-corner) relative permeabilities and zero capillary pressure in the fractures, without a clear understanding of how these two parameters affect simulation accuracy and with no practical method for selecting alternate values. The present study uses the theoretical work of Rossen and Kumar (non-straight-line fracture relative permeabilities)1,2 and of Firoozabadi and Haugh (non-zero capillary pressure in rough-walled fractures)3 to quantify prediction errors and to demonstrate a method for selecting the correct set of relative-permeability and capillary curves for a particular simulation. Our results indicate that using straight-line relative permeabilities can lead to predicted oil-recovery errors as high as 70% in water-oil systems and to underestimating oil production times in some gas-oil systems by as much as a factor of three. In gas-oil systems where gas flows into the fractures, oil recovery from the matrix blocks could be underestimated by a factor of almost two when fracture capillary pressures are set at zero.
The Development and Utilization of Scattered and Remote Gas Field Resources with HSE
Authors: Yanming P. , Jian Z. , Xiaoyang L. , Jianwen Y. , Changming Z. , Xiaomu W.
Published: December 2007

The international community encourages fully use of natural gas, which is used to replace coal and "makes good inadequate oil with gas". It is expected that by the year of 2020, natural gas production will be increased from 25% to 40% in present energy structure in the whole world. And its rapid and stable development period could last for 40~50 years and it will be one of the most important energy sources in the preliminary period of time in the 21st century. At present, 40%~50% of natural gas resources are accumulated in scattered and remote medium and small-scale natural gas fields in the world. Since these gas fields are usually located in remote and frontier areas, transporting the natural gas, light hydrocarbons and CO2 resources of these areas by pipeline is not reasonable in regard to economy, technology and HSE.

In this paper, appropriate technical measures for separation, treatment, storage, transportion and utilization of natural gases are proposed aimed respectively at medium and small quantity of gas resources. The recovered natural gas and CO2 can be reinjected into oil wells in order to improve oil recovery efficiency. In addition, CO2 can be utilized to treat wastewater containing of CaCl2 to reduce environmental pollution. Some wastewater can be utilized to produce gas hydrate in order to store and transport gas resources.

In summary, flexible measures are needed in gas separation, treatment, storage, transportation and utilization on the basis of gas quantity, which will provide resources guarantee for fully utilizing available resources and obtaining maximum benefits.
A New Breed of Petroleum Engineering Education in the Middle East
Authors: Aggour T.
Published: December 2007

As the desire for nationalizing the work force in many Middle Eastern national oil companies increases, there is an increased need to provide suitable educational programs to produce highly qualified native engineers. While petroleum engineering university graduates in the Middle East will face many of the same technical issues as their counterparts around the world, the nature of their employment and their career progression can be significantly different. The unique structure of many of the national oil companies in the Middle East as well as the unique student pool allows and calls for the establishment of petroleum engineering education programs that may differ from programs in other regions of the world. This may involve modifying the structure and delivery of traditional courses of study. Universities in the region are faced with the challenge of developing programs that can more effectively address these unique needs while maintaining academic integrity and rigor, and meeting international standards for academic accreditation and excellence. This paper discusses the nature and needs of the regions employers and potential employees, and the response of regional academic institutions to cater to these needs. Examples are given demonstrating the efforts at some regional universities that are attempting to address the specific needs of the regional industry while achieving and maintaining international standards of excellence.
The Importance of Leadership in Developing and Maintaining an Effective Safety Culture Within an Organisation
Authors: Barrett J. P. , Cram R. S.
Published: December 2007

Proposal

It has been said that leaders are born, not made. To a certain extent, this is true. Many corporate heads are undoubtedly possessed with a degree of leadership skills. In most cases though, these leadership skills are centred on their ability to lead and manage a business from an economic perspective. Economics, finance, law, market sectors, corporate growth, mergers and acquisitions, business strategy etc.

Throughout their careers, business leaders often attend numerous seminars and training courses designed to improve their skill sets in these and many other similar disciplines with the focus, quite understandably on improvements to the performance of the business. Few spend much time in the business of safety and few have been lucky enough to survive the "eye opening event" which has befallen many a corporate chief; sometimes with disastrous consequences.

The safety culture of an organization is a direct consequence of the attitudes of the chief executive officer. It percolates from the board of directors, through the senior executive all the way to the workforce. His approach becomes the organisation's approach. His attitude, the attitude of everyone down the line.

This paper examines the essentials of being an effective leader in the field of HSE. It considers what factors go to make up a good safety leader and presents suggestions about how today's corporate bosses can instil a culture of safety first at every level in the organization.
The Perfect Wellbore!
Authors: Mason C. J. , Chen D. C-K
Published: December 2007

Wellbore quality is a term frequently used in the drilling community; however its meaning is not well understood, its context frequently confused and its value underestimated. For most drilling engineers, a quality wellbore is one associated with a directionally drilled borehole that is smooth, in-gauge, and has minimal spiralling. The claimed benefits of such a wellbore includes improved drilling performance, ease of running casing, better logging tool response, and highly competent cement jobs. To date it has been too difficult or too complex to relate such benefits to wellbore quality in a meaningful and measurable way. In order to reduce existing subjectivity, a procedure has been devised whereby wellbore quality can be measured in a practicable way. This resulting process is embedded in what is called the Wellbore Quality Scorecard (WQS). The system works by individually scoring drilling, tripping-out and casing running responses for any drilled hole section. A total score ranging from 0 to 20 is computed, where 20 is considered to be "The Perfect Wellbore". This represents significantly better than expected torque and drag responses from drilling, tripping-out of hole and casing running. Practical applications of the WQS are demonstrated on both horizontal and extended-reach wells.
Modelling the gas well liquid loading process
Authors: Dousi N. , Veeken C. A. M. , Currie P. K.
Published: December 2007

Liquid loading is a serious problem in areas where gas fields are maturing. An analysis is provided of the production behaviour over time of liquid-loaded wells. This shows clearly that these wells can operate at two different rates, a stable rate at which full production is taking place and a lower metastable rate at which liquid loading effects play a role.

A model has been constructed which enhances the understanding of the process of water build up and drainage in gas wells. It assumes a single gas and water co-production point and a single water re-injection point. As expected a water column is built up in the well as soon as production takes place below the critical rate. As observed in the field, for good inflow performance a metastable flowrate can be observed. At this state the water re-injection and water coproduction rate are equal to one another and the water column height stabilizes.

A sensitivity analysis has been carried out to determine how well parameters influence the metastable flowrate, the time required to reach this metastable rate, the corresponding water column height and the shut-in time required to drain this water column. The results of the analysis indicate that significant metastable flow rates occur in wells which have good inflow performance, a low water gas ratio and a large distance between injection and production point.

Furthermore a steady state analytical solution has been derived for the metastable rate and stabilized water column height confirming the numerical analysis results.
Measurement of Proppant Transport of Frac Fluids
Authors: Harris P. C. , Morgan R. G. , Heath S. J.
Published: December 2007

The object of hydraulic fracturing is to produce a propped fracture extending from the wellbore. Extensive time and effort are expended in measuring rheological properties of crosslinked fluids (without proppant) under simulated downhole temperature and shear-history conditions. Normally, it is assumed that if a fluid meets certain minimum viscosity conditions, it will transport proppant successfully. Measurements of actual proppant transport under dynamic simulated downhole conditions have been attempted and described, but such measurements have been very cumbersome and require significant equipment and expense to execute. Such measurements are well beyond the scope of routine QA/QC analyses.

A proppant viscometer recently constructed can measure fracturing fluids containing propping agents across a wide range of concentrations. The device was designed to work as a conventional Fann Model 50-type viscometer. This unique viscometer has been used to measure typical fracturing fluids containing realistic concentrations of proppants, at temperatures and times up to several hours, representative of actual fracturing treatments. The measurements show regions of elastic transport typical of viscoelastic fracturing fluids where proppant is transported efficiently, usually followed by regions of purely viscous transport where proppant slowly settles.

The advantage of the new proppant viscometer is that all components of a fracturing fluid, including proppant, can be tested. Shear-history effects of proppants on frac fluids are usually unknown or ignored, but such effects were observed in this work. Breakers were usually added to the fluids, showing reasonable times when the crosslinked fluid no longer transported proppant efficiently and proppant began to settle.

This paper shows how different types of fracturing fluids can support proppant based on their chemical type, i.e. metal and borate crosslinked fluids, linear gel fluids, and surfactant gel fluids. Proppant concentrations are also considered. The physical characteristics of the proppant viscometer are also addressed.
Crude Oil Contaminated Soil Clean Up With Bioremediation: A Case Study and Implementations in Minas Field, Indonesia
Authors: Rumbiyant E. , Hermiani F. , Aji B. S. , Nugraha S.
Published: December 2007

PT. Caltex Pacific Indonesia (CPI) is strongly committed to maintaining a clean environment for nearby communities while providing safe and healthy working conditions for its workers and business partners. While operational standards and regulations have improved since operations began in 1952, a variety of incidents over the years have caused soil in some of the surrounding areas to be contaminated with crude oil. CPI is applying bioremediation techniques to mitigate this impact.

Bioremediation is a batch process utilizing microbial digestion of hydrocarbons to clean up soil contaminated with crude oil. Bioremediation land farming was selected because it is a cost effective method, it complies with Government of Indonesia (GOI) regulatory requirements and it is a technology with proven success for producing an end product which is safe to be utilized for re-vegetation and landfill within certain restrictions for areas within Minas Field. The process involves excavation of the soil, hauling the material to Soil Bioremediation Facilities (SBFs) where it is spread and processed (land farmed) by tilling (aeration), irrigated, fertilized with nutrients (fertilizer), monitored regularly by analyzing soil samples for Total Petroleum Hydrocarbon (TPH). Once the TPH meets levels within acceptable concentrations stated in GOI regulation, the soil is removed from the sites and redistributed in predetermined areas based on specific criteria. The average cycle time of this complete process is 5 months.

In CPI's Minas field alone, 5 bioremediation sites are operated continuously providingfor a processing capacity of 45,000 cubic meters of soil per year resulting in approximately 150,000 m3 of soil being processed between 1997 to today. During this time CPI made great strides in improving the process through creating more sites, trying different equipment and operating methods. However, CPI continues to seek new innovations and research to increase efficiency, reduce overall cycle time and increase capacity.
North Sea Hannay Field Case History: Perforating through a cased-hole gravel pack to significantly increase oil production
Authors: Peggs J. K. , Duncan B. S. , Weatherstone P. M. , Webster C. McK.
Published: December 2007

The Hannay field is located in Block 20/5c of the North Sea, approximately 150 km Northeast of Aberdeen. The development consists of two subsea producers tied back to Buchan via a 13.5 km pipeline. The production mechanism at Hannay is depletion with significant aquifer pressure support.

The Hannay Field commenced production from a horizontal subsea well (Hannay 1) at an initial rate of 18,000 stb/day. However, the initial months saw approximately 9 tonnes of sand production transported into the production separators.

In an attempt to mitigate sand production, the well was flowed below 10,000 BFPD. Reduced flow rates from the Hannay 1 well provided economic justification for a second producer. Hannay 2 was drilled approximately 1 year after field start-up. Due to sand production from the Hannay 1 well and sensitivity to water-based gravel pack fluid, it was necessary to complete the well with a cased-hole gravel pack. The installation of the gravel pack resulted in a large skin of 100. Acid was used to reduce this skin to approximately 50; however, the Hannay 2 productivity still remained significantly impaired.

This paper presents the engineering studies conducted to evaluate and justify the perforation of the gravel pack in the Hannay 2 well to reduce well damage. These include rock mechanics, sand prediction analyses, and reservoir simulation work to evaluate the potential benefit and optimum interval to perforate to maximise oil recovery.

Detailed well intervention planning was undertaken and successful operations conducted to increase oil production from the well by 3,000 BOPD. Incremental reserves of 1.0 mmstb will be realised for a cost of under £2 million. This shows the importance of a long clean-up period for wells that initially produce sand before adopting a conservative sand control strategy.
Marco Polo Deepwater TLP: Completion Implementation and Performance
Authors: Burman J. , Renfro K. , Conrad M.
Published: December 2007

Novel well completion techniques and exceptional field execution allowed the six well completions on the Anadarko operated Marco Polo Deepwater TLP project in Green Canyon 608 to be accomplished in world-class fashion. All six wells (seventeen frac packs) were placed on production in only 168 days, including 14 days lost due to storms, after riser tie-back operations were complete. An operational efficiency of 85%, with weather downtime accounting for 9% and other lost time accounting for 6%, was obtained during the completion campaign.

This paper will focus on how the implementation challenges of completing seventeen zones in six deepwater dry-tree wells with a 1000 hp rig were met, and will highlight a number of concepts and technical firsts that can be applied to other deepwater development projects.
Effect of EOS Characterization on Predicted Miscibility Pressure
Authors: Stalkup F. , Yuan H.
Published: December 2007

An equation of state (EOS) is not a unique representation of the PVT behavior against which it is tuned. Two equations of state with different parameters may appear to predict the same experimental PVT data about equally well. However, they may give very different simulated slim-tube recovery as well as analytical predictions of minimum miscibility pressure. In addition to PVT data, tuning the EOS against slim-tube data is advisable.

This paper illustrates the above remarks for three different reservoir fluids that have different amounts of PVT data to tune the EOS against. These examples show that what appear to be equally acceptable EOS characterizations with regard to PVT data predictions can predict differences in miscibility pressure as much as 500 to 1000 psia. In an example simulation in a heterogeneous reservoir cross section, these differences in EOS characterization caused 7 to 22% differences in predicted incremental recovery.
EIA Study to Identify Effect of Gas Flaring on Rice Cultivation in Oil Fields of Assam
Authors: Bose C. , Sharma K. K.
Published: December 2007

Oilfield in Assam are located in and around the rice fields. Rice crop in the vicinity of flare pits near oil collecting stations (OCS) get illuminated throughout and high spikelet sterility is caused. In the present study, attempt is being made to determine the response of some traditional and modern cultivars of different duration groups under prolonged photoperiod near the pit. Photoperiod insensitive medium duration variety like Jaya was least affected the light intensity. Due to prolong light hours, days to 50% flowering were affected in traditional long duration variety. Amongst the yield attributing characters, ear bearing tillers/hill, sterility (%), panicle length and grains/panicle were effected due to prolonged light hours; while light period had little effect or no effect on plant height, total number of tillers/hill and test weight.
An Enduring Commitment to Sustainable Community Development in Myanmar: The Yetagun Socio-Eco Development Program
Authors: Musa A. G. , Tarnoff A.
Published: December 2007

In 1997, three years before the production of gas and condensate went on-line in the Yetagun Field of the Andaman Sea in territorial waters of the Union of Myanmar, the start of the Yetagun Socio-Economic Development Program represented the collective commitment and vision of Yetagun Joint Venture Partners. The objective is to improve the social and economic condition of local residents in the onshore pipeline corridor of operations and the country as a whole.

The Yetagun Socio-Economic Development Program has been implementing a series of complementary programs to address the most essential health, education and income generating needs of disadvantaged communities, especially women and children.

The Yetagun Socio-Economic Development Program has reached over 150,000 beneficiaries. Immediate and measurable improvements in the quality of life for thousands of beneficiaries have also strengthened the capacity and empowered communities with the knowledge, skills and tools to achieve long-term and sustainable impact for generations to come.
Revisiting Reservoir Flood-Surveillance Methods Using Streamlines
Authors: Batycky R. P. , Thiele M. R. , Baker R. O. , Chung S. H.
Published: December 2007

This paper revisits classic flood surveillance methods applied to injection-production data, and how such methods can be improved using modern streamline-based calculations. Classic surveillance relied on fixed patterns and geometric based well-rate allocation factors (WAF's). Here we compare conclusions about pattern performance from classic surveillance calculations against surveillance results using flow-based WAF's as computed from a streamline surveillance model. We show that very different conclusions on pattern performance can be reached. Rather then fixed patterns, we also introduce injector centered patterns as the elementary surveillance unit with offset producers being those that an injector is connected to at any time event. Injector centered varying patterns give a better measure of an injector's true effectiveness since all offset oil it is responsible for is counted, rather than just production within a pre-defined pattern. Here too we show that decisions about how to manage a flood can be quite different than decisions reached using a fixed pattern analysis.

In the second part of this paper we illustrate how much data is required to build a relevant surveillance model. We compare WAF's and offset oil production as computed from full history-matched flow simulation models against surveillance models for several field cases. Our comparisons show that as long as offset well rates are a function of neighboring well rates, as is typical in waterfloods, then only first order flow effects are required in a surveillance model. First order flow effects required would include, well locations, historical rates, gross geological bodies and major flow barriers. In other words, because well rates are already a reflection of geology, simply setting up a surveillance model with the proper geological connectedness will lead to streamline models that give similar inter-well fluxes, as more complex history matched simulation models.
Optimized Well Location by Combination of Multiple Realization Approach and Quality Map Methods
Authors: Cottini-Loureiro A. , Araujo M.
Published: December 2007

The determination of the location of new wells in an oil reservoir is a complex problem that depends on reservoir and fluid properties, well and surface equipment specifications, geographical conditions and economic criteria. The final method to be used for field development should be based on the use of a reliable method for well location, oriented to reduce uncertainty, minimize costs and maximize the asset value. Reservoir simulation is recognised as one of the most reliable tools for defining the optimum production strategy. However, forecasting by reservoir simulation techniques bears risk as result of the uncertainty in the input data. The conventional approach to plan the number of production wells and their locations is by a tedious and costly trial and error process, where the final result depends on the ability of the reservoir engineer to fully understand the reservoir behaviour and the operational limits.

Here, we present a new approach for optimal well location that was developed by combination of multiple realization and quality map methods. The proposed methodology starts from the static reservoir model in which main parameters are identified to reduce the number of simulation runs required for an optimized dynamic reservoir model by using the multiple realization approach. The study continues by determining the quality map for the reservoir, which is aimed to identify areas from where the hydrocarbon production is expected to reach a field maximum. This is performed by evaluating each possible well position at different locations up to finding the maximum production, without well interference or unphysical behaviour in well response.

This approach was tested on the Maureen field, a North Sea reservoir, finding optimal well placement with an improved production. Numerical results obtained by applying the combined methodology provided larger hydrocarbon recovery from the field those results obtained by just using the two involved methods separately in 20 years of production. Predicted production values were significantly larger that those reported in actual field production. The methodology found spots where the forecasted production might be significantly larger if wells were located in coordinates other than some of the actual wells._Thus, the proposed method could be used as a tool to reduce uncertainty in development fields and an important technique towards an optimal asset management.
The Application of Cutoffs in Integrated Reservoir Studies
Authors: Worthington P. F.
Published: December 2007

Methodologies have been developed for applying net reservoir and thence net pay cut-offs in cases of primary and waterflood depletion. The cut-offs are dynamically-conditioned to be reservoir-specific, i.e. they are tied back to a reference permeability parameter in a way that is driven by the reservoir data themselves. They also honor scale, where feasible, and are conformable with any pertinent rock-typing. For primary depletion, the Leverett equivalent circular pore diameter has been used to distinguish between reservoir and non-reservoir rock. This composite parameter can incorporate mobility for multiphase work. It is linked to a discrete core porosity under simulated reservoir conditions, so the adopted net-reservoir cut-off is expressed as a limiting porosity. For waterflood depletion, an extrapolated end-point relative permeability has proved effective for the same purpose. Here, the zero endpoint relative permeability is linked to a conventional "absolute" core permeability corrected to reservoir conditions. Porosity is tied back to this limiting absolute permeability so that the net-reservoir cut-off is again expressed in terms of porosity. Consequently, in both cases, the discrete porosity cut-offs have a dynamic significance. Other cut-off parameters, such as shale volume fraction and water saturation, can be tied back to these. A proposed workflow for applying dynamically-conditioned cut-offs allows data character to drive their use in integrated reservoir studies. The workflow constitutes a basis for greater technical consistency in the estimation of ultimate hydrocarbon recovery. The treatment is not exclusive, and other approaches to the determination of net pay will emerge as more reservoirs are considered.
Deploying Common Process Across Global Wells Teams—Integrating an Online Project Management Application with Effective Behaviours to Enable High Performance
Authors: Sawaryn S. , Dressler D. , Been K. , Bailey T.
Published: December 2007

BP has successfully deployed a web based project management application across the global wells teams to support common processes used in well delivery. Widespread use of the application is now made in drilling and completions activities and other planning functions within the wells community. This is just one of the tools that have contributed to the 19% drilling and completions performance improvement recorded in BP during 2003.

The project's goal is to standardise the use of proven common processes, creating a shared repository for critical knowledge, reducing time for project initiation and planning, managing risk and supporting the stage gate decision making. An extensive management reporting capability also reduces the administrative burden.

Positive results include quicker start-up of new teams and improved planning. The keys to success are organisational commitment to the common processes and the use of proven project management practices in drilling and completions activities. Behaviours have also been addressed. Over 90% of the application was based on established, commercially available software, increasing reliability, reducing implementation risk and enabling the developers to focus on the key functionality and user interface. The application's process templates are regularly reviewed and are updated periodically to ensure continuous improvement and long term sustainability.

This paper contains a summary of the common processes and presents a case study of the project, its goals, results, critical success factors, challenges and lessons learned, supported by several examples. The paper will be of interest to both managers and engineers.
History Matching of Naturally Fractured Reservoirs Using Elastic Stress Simulation and Probability Perturbation Method
Authors: Suzuki S. , Daly C. , Caers J. , Mueller D.
Published: December 2007

The application of elastic stress simulation for fracture modeling provides a more realistic description of fracture distribution than conventional statistical and geostatistical techniques, allowing the integration of geomechanical data and models into reservoir characterization. The geomechanical prediction of the fracture distribution accounts for the propagation of fracture caused by stress perturbation associated with faults. However, the challenge lies in estimating the past remote stress conditions which induced structural deformation and fracturing, the limited applicability of the elasticity assumption, and the latent uncertainty in the structural geometry of faults. The integration of historical production data and welltest permeability into geomechanical fracture modeling is a practical way to reduce such uncertainty. We propose to combine geostatistical algorithms for history matching with geomechanical elastic simulation model for developing an integrated yet efficient fracture modeling tool.

This paper presents an integrated approach to history matching of naturally fractured reservoirs which includes 1) fracture trend prediction through elastic stress simulation, 2) geostatistical population of fracture density based on fracture trend map, 3) fracture permeability modeling integrating fracture density, matrix permeability and welltest permeability, and 4) numerical flow simulation and history matching. All of these implementations are incorporated into a single forward modeling process and iterated in the automatic history matching scheme. To obtain a history match on a reservoir model, we jointly perturb the large-scale fracture trend and local-scale geostatistical fluctuations of fracture densities rather than perturbing permeability calibrated from fractures. This strategy enables us to preserve the geological/geomechanical consistency throughout the history matching process. The geomechanically simulated fracture trend model is calibrated to both production data and geological structure map (faults and horizons) by finding the optimum remote stress condition for elastic stress-field simulation. The latter is achieved by matching the actually observed structural deformation trend with the simulated one. The smaller-scale fluctuation of fracture density is simultaneously history matched through the probability perturbation method of Caers (2003)1,2. The result of synthetic reservoir application is presented.
Worldwide First Run in Hole of a Dope-Free 13Cr Production Tubing String
Authors: Rignol J. , Parde A. , Thoreau E. , Verdillon L.
Published: December 2007

Thread compounds are used on a common basis throughout the full life of Oil & Gas Tubular Goods (OCTG), whether as a storage compound applied in the mill, or in the yard, or as a make-up compound for running in hole.

Dischargeable compounds have an impact on the environment, due to some of their components such as lead and due to the quantity released. Past initiatives - like green dopes - have brought valuable, but only partial resolution to this problem.

The optimum solution is the increasingly popular dopefree connection approach. This paper presents the first worldwide implementation of a complete Cr13 production string applied with a dopefree connection: 16000 ft of 4" 1/2 13%Cr-L80 Premium CLEANWELL© tubing joints run in a North Sea offshore gas well in the Netherlands.

The paper explains the specific requirements for using this new "no application - no discharge" lubricating film. It also examines the present QA-QC procedures (storage, thread inspection, tally, drift etc…) that ensures" no leaks" in the production string as well as the lessons learnt throughout the entire implementation of this dopefree system.

Finally, in addition to the improvements of existing HSE practices, the paper highlights the other benefits recorded during this first implementation, including rig time savings, improvement of the protection of the threads, reduction of pipe handling.
Integration of Microseismic Fracture Mapping, Fracture and Production Analysis With Well Interference Data To Optimize Fracture Treatments in the Overton Field, East Texas
Authors: Mayerhofer M. J. , Bolander J. L. , Williams L. I. , Pavy A. , Wolhart S. L.
Published: December 2007

Proposal

This paper discusses the integration of microseismic fracture mapping with fracture engineering, well production results and offset well interference data in the Overton Field, East Texas. Target formation is the Taylor Cotton Valley at depths of about 11,500 ft. The fracturing program in this field included different types of waterfrac and linear gel hybrid frac treatments, which were compared to evaluate the optimal type of fracture design in this area. Detailed production analyses were performed to evaluate well performance in conjunction with fracture geometry measurements provided by microseismic fracture mapping results, calibrated fracture modeling and direct production interference data, which provided interesting insights into effective fracture lengths, reservoir quality, and drainage areas.

Microseismic fracture mapping1,2,4,6,7,14-17 indicated that created fractures are very long. There is compelling evidence that effective hydraulic fracture lengths are also very long, as immediate well interference can be detected in wells that are located along the fracture orientation with very large interwell distances. This means that there is a conductive hydraulic fracture path in place over large distances, with fractures overlapping and linking up wells. One well in this study area was temporarily killed by a fracture treatment in an offset well but production was restored within one day. There was no evidence for a wide fracture network (as has been reported in the Barnett shale), but there may be a small-scale fracture network within a narrow area around the hydraulic fracture.

Production modeling indicates that the permeability feeding the long hydraulic fractures (perpendicular to frac) is on average very low as indicated by production modeling. The low permeability and long fractures will create slim "cigarlike" drainage areas that should be taken into consideration for well placement and spacing strategies.

The results of this work illustrate the application of microseismic mapping to calibrate fracture models3,8,9,10,13 and, with the subsequent integration of production and interference data, to improve well placement and field development strategies. The paper also provides recommendations for optimizing future fracture treatment designs and explores different treament types (waterfracs, and linear gel hybrid fracs) and the effect of increasing job sizes.
Development of Equations and Procedure for Perforation Inflow Test Analysis (PITA)
Authors: Rahman N. M. A. , Pooladi-Darvish M. , Mattar L.
Published: December 2007

Recently short emission tests have been getting attention due to economics, environmental issues or time constraints. Thus, well-testing is sometimes reduced to perforating the well and analyzing the inflow characteristics. The objective of a Perforation Inflow Test Analysis (PITA) is to estimate the initial reservoir pressure, permeability and skin, immediately after perforating the well. This information can be used for evaluating future development strategy. During the entire test period, the surface valve is kept closed, and the formation fluid enters the closed chamber (casing or tubing space) as initiated by a lower cushion pressure than the initial reservoir pressure. However, special analytical procedures are required for analyzing the data, captured through surface or subsurface monitoring, because these perforation inflow tests are shorter than conventional well tests.

In this study, the working equations for analyzing these short tests are developed and presented for both gas and liquid (oil or water) wells, and the procedure required for calculating meaningful estimates of the reservoir parameters will be highlighted. The equations are based on some approximations of the slug-test solution in Laplace space. The radius of investigation during the perforation tests will be estimated, and it will be shown that in presence of measurement errors, radius of investigation will grow to a maximum value. Running the tests for anytime longer will detect just the noise.

A special derivative, called the impulse derivative, will be used to determine if the data collected is sufficient to yield meaningful results from a PITA. It is particularly important that the wellbore flow has diminished to a low level and the reservoir-dominated flow has fully established, if the estimates of initial reservoir pressure, permeability and skin are to be acceptable.