bluuebunny/crossref_metadata_2025 huggingface dataset:
Material and Completion Equipment Selection for HPHT Sour Gas Field Development in Indonesia : Case Study
Authors: Purwagautama Gustioro , Andika Rizky , McCalvin David , Pleshkov Dmitry
Published: February 2011

The Lematang Block in South Central Sumatra have an estimated total reserve of 330 BCF, the expected production life of 10 years is of substantial importance to MEDCO the fields operator. Wells in this field contain 32% CO2, 100-ppm H2S, BHP of 10,500-psi and BHT 408 degF and are therefore categorized as HPHT gas wells. The initial two wells were completed by the previous operator using 22Cr tubular material and 13 Chrome based material accessories. However, operational difficulties from material deterioration were identified. Optimization of the completions durability with the consideration of the economics of the completions was of paramount concern when selecting the materials and the completion tool designs.
Barge Assisted Coiled Tubing in Malay Basin of South China Sea - Pilot Project Success Story
Authors: Razak M Hairi , Noordin F. M. , Yusoff Afendy , Wibisono R.
Published: February 2011

PETRONAS Carigali Sdn. Bhd. (PCSB) operates a handful of small platforms at offshore Peninsular Malaysia, in the Malay Basin area, located in the South China Sea. Most of these platforms were designed with limited crane capacity of maximum 5 MT load and small deck space area that only suffice to accommodate slickline operations. After many years of production, the fields have started experiencing sand production, high water cut and a large skin factor. Thus, well interventions and treatments such as matrix stimulation, water shut off or sand clean out are required to sustain and enhance the production rate.

Coil tubing (CT) well intervention is the most effective method to achieve these objectives. However, with limited platform facilities, it is a tremendous challenge to have big CT equipments catered on board. The solution to this is to have a minimal number of equipments on the main deck whilst the crane lifting will need to be done from the barge. CT operation with barge assistance was evaluated and finally opted for to execute the jobs at PCSB's small fields. Throughout the operation, only the coil tubing injector head, jacking frame and CT control cabin were erected on the platform whilst the remaining equipments were stationed on the barge.

As this was the first CT barge assisted operation in the Malay Basin of South China Sea, two platforms were selected for the pilot campaign. The jobs objectives include water shut-off, wax and sand clean out that has a potential enhancement of 1000 bbl of crude. This paper describes the operational success stories, campaign preparation, proposed work programs, barge selection, jobs execution and project lessons learned.
Long-Term Comparison of Production Results from Open Hole and Cemented Multi-Stage Completions in the Barnett Shale
Authors: Lohoefer Darrell , Snyder Daniel J. , Seale Rocky
Published: February 2011

The Barnett Shale is considered to be a prototype for other shale plays in North America and throughout the world because it was the first shale play to be developed. This paper describes production results from two horizontal wells in the Barnett Shale completed with open hole, multi-stage fracturing systems (OHMS) compared to direct offset wells with conventional cemented liner, “plug and perf” completion.

Three years of monthly and cumulative production totals are analyzed and discussed. This paper also discusses the system details, the fracture methods used, as well as the operational efficiencies of OHMS compared to other horizontal completions methods.

These results demonstrate that OHMS technology provides a long-term option for the life of wells in shale plays. The estimated ultimate recovery (EUR) values for shale gas plays has been a hotly contested issue over the past year due to observed “catastrophic” production decline curves. This paper discusses how the choice of completion method can affect EUR by analyzing long-term production data from offset wells completed by cemented liner plug and perf versus OHMS. This knowledge can be applied to any unconventional shale reservoir.
Lithogeochemikal Features of the Jurassic Terrigeneous Sediments Formation Within Vat'-yegan Oil Field (West Siberia)
Authors: Kajachev N. F. , Kudamanov A. I.
Published: February 2011

We report here the results of lithogeochemical studies of silt-rich mudstones of the Tyumen, Vasyugan, Georievsk, and Bazhenov formations and sandstones and siltstones confined to the YuV11, YuV12, and YuV2 pay zones within the Vat-Yogan oil field. Chemical analysis was performed to define chemical composition of 370 core samples To detect major and trace elements an X-ray fluorescence method was used. To interpret the results of the study an R-mode factor analysis as well as nomenclatures, classifications and lithogeochemical techniques developed by F. J. Pettyjohn, M. M. Herron, and Ya. E. Yudovich were applied.
The Influence of Geological and Technological Factors on Enhanced Oil Recovery
Authors: Silin M. , Eliseev D. , Kulikov A.
Published: February 2011

The proposed report presents an analysis of the effectiveness of enhanced oil recovery (EOR), performed on the fields Western Siberian region in the period from 2002 to 2009. Analysis reached more than 1000 injection wells and processed about 5000 producing wells.

According to the analysis of the effectiveness of EOR determining geological parameters are partition factor and directional permeability of the reservoir, it is shown that the increase in efficiency with increasing partition factor is due to increased duration of effect.

It is noted that the decrease in the effectiveness of EOR occurs with increasing development of oil reserves. It is shown that the effectiveness of the EOR is the highest in the base water cutting wells about 80%. It was found that a decisive influence on the effectiveness of EOR provides value target intensity water cutting of well production, which expresses the anticipation of the current average water cutting of well production from the current development of initially recoverable oil reserves, shows the degree of backwardness of waterflooding processes from the processes of water cutting of well production. The analysis showed the benefits of integrated technology EOR, different injection gel-forming and stimulation chemical compositions. The advantages are the increase in injectability of injection wells with decreasing water cutting of well production. In order to optimize the flow of reagents for each field revealed the dependence of the efficiency of EOR from specific volume of the margin, whereby determine the optimum value of this parameter.

To confirm these results, we have conducted work on mathematical modeling of the EOR, which agree well with practically the results.

The practical value of the executed analysis of fishing activities is considerably improved the accuracy of selection of technologies EOR as a direct composition of chemical reagents, and the volume pumped into injection wells tracks.

Based on the analysis it was concluded that work on the runway injection wells on the fields of Western Siberia have led to increased oil recovery;

This work has significantly clarified the criteria for effective use of technology EOR; To a large extent optimized specific volumes of injected chemical compositions.
Fracture-Based Strategies for Carbonate Reservoir Development
Authors: Davletbaev Alfred , Baikov Vitaly , Doe Thomas , Emchenko Olga , Zainulin Aleksey , Igoshin Andrey , Fedorov Aleksey
Published: February 2011

Carbonate reservoirs present both opportunities and challenges, especially in rocks that contain multiple, heterogeneous porosities. This study addresses a large carbonate reservoir with complex porosity types including porous matrix, fractures, faults, and vuggy zones. A fracture-focused strategy considers how these porosities behave in oil production, and uses this understanding to improve reservoir productivity.

The subject of this work is a major carbonate reservoir that was initially developed by conventional methods. These approaches emphasized matrix properties using petrophysically-interpreted wireline logs. The early stages of production, which did not include pressure maintenance, found anomalous behaviors that were inconsistent with a matrix-only reservoir. The existing petrophysical data, which are valid only for porous rock, could not address fracture-based hypotheses.

A program of fracture studies supported a re-analysis of the production strategies in light of reservoir's observed behaviors. The fracture-focused strategy employed FMI image logs along with production logs (PLT surveys) and temperature surveys. These well-based tools identified the locations of flow and their associated geologic features, which are appeared to be mainly fractured and vuggy horizons. Coring activities validated the FMI interpretations.

A reexamination of well tests using supported a single-porosity, fracture flow model. Pressure derivative interpretations using fracture-based conceptual models associated well performance with geologic features, including both the vuggy zones and faults.

The fracture-focused characterization program has developed improved conceptual models of the reservoir to support evolving production approaches including well acidizing, and other. The paper provides examples of successful well operations performed after appropriate field research.
Thermal Modeling for Characterization of Near Wellbore Zone and Zonal Allocation
Authors: Ramazanov A.Sh. , Valiullin R. A. , Sadretdinov A. A. , Shako V. V. , Pimenov V. P. , Fedorov V. N. , Belov K. V.
Published: February 2011

This paper describes a new method based on the analysis of non-steady state wellbore temperature distributions impacted by geothermal temperature profile, Joule-Thomson and adiabatic effects in reservoir flow to describe near wellbore parameters such as permeability distribution and to estimate flow rate distribution between producing layers.

The solution of the inverse problem with respect to parameters of near wellbore zone is based on the quantitative analysis of the transient baro-thermal effects resulting from the single-phase fluid flow from the reservoir into the wellbore. In the steady state case the reservoir thermal effect is the same as the throttling (Joule-Thomson) one. It is reduced to the adiabatic effect while the fluid is stagnant. In the general case for non-steady state flow the change of reservoir fluid temperature is a combination of frictional heating and cooling resulting from the expansion of the fluid. Non-isothermal well testing (NIT) relies on the analysis of these fluid temperature changes. The method discussed in this paper allows evaluating parameters of near wellbore region (permeability and radius of damaged zone) and could be complimentary to the conventional well testing practices for a single-layer reservoir and to estimate flow rate distribution among the pay zones in a multi-layer case (zonal allocation). The paper develops mathematical models and presents the results of numerical simulation for transient processes after the start of the production phase and during well test operations including multi-rate testing.

Limited to the particular cases of unsteady processes after specific wellbore operations (changes of production regimes and shut-ins), the transient analytical solutions assume that the fluid may be considered incompressible and that no conductive heat transfer occurs. In order to take into account compressibility and thermal conductivity, detailed numerical modeling has been performed. The paper compares the numerical results to experimental data and shows that the fluid heat capacity in wellbore perforated zone must be considered for appropriate interpretation of initial bottomhole temperature change versus time, in particular for small rates. Based on the analysis of the simulation results, an inverse model solution for the estimation of the near wellbore zone parameters from reservoir fluid temperature and wellbore pressure transients is proposed. The method comprises first-order estimation from analytical solution and their further numerical refinements by non-linear regression for the system "reservoir-wellbore". Example of interpretation of non-isothermal well testing field data is presented demonstrating the usefulness of this new methodology.
Development of Inflow Profiling Criteria for Low-Rate Horizontal Wells on the Basis of Physical Laboratory Experiments and Field Studies
Authors: Valiullin R. , Yarullin R. , Yarullin A. , Shako V. , Parshin A.
Published: February 2011

Russian experience with geophysical studies in horizontal wells producing under conditions of low rates and multiphase separated flow shows that traditional methods using mechanical flow rate measurements and temperature logging are not effective in identifying the producing intervals. Results of physical experiments conducted in a laboratory flow loop established that flow structure in horizontal wells producing at rates from 2 to 250 m3/d is mainly determined by the wellbore trajectories and phase rate ratios. In these horizontal wellbores there is a zone of stagnant fluids, as well as significant vertical gradients of fluid velocities and temperatures.

Taking into account actual values of total and phase rates typical for horizontal wells in the Russian Federation, experimental works were carried out in a flow loop at Bashkir State University to develop criteria for flow profiling and methodology for wellbore field measurements in low-rate wells.

Analyses of the laboratory experiments and field data established the need for precise data on wellbore trajectory, taking into account the phase distribution across the flow at the tool location; the need for local velocity measurements in the temperature field along the entire horizontal wellbore trajectory; and the need for different well operational regimes. Based on the results of the experiments, actual field data were reinterpreted. Recommendations were developed for methodical guidelines for field data interpretation, and criteria were formulated for identification of oil and water inflow intervals in low-rate horizontal wells.
Recompletion of a Horizontal Water Injector Well Purely on E-Line Made Feasible and Viable with Wireline Tractor Technology
Authors: Kueh P.T. , Lam F.S. , Lim E.C.
Published: February 2011

A water injector located in an offshore Sabah field, Malaysia was sidetracked and completed as a single string completion on 13 September 2006. This water injector was designed for 10,000 barrels per day of seawater injection. It was completed as open hole with swellable packers targeting H sand only. However, due to differential sticking while running completions, the completion string became stuck at 700 feet above the intended setting depth. Since then, the well had been closed to avoid the risk of nearby fault activation.

Due to the initial injection behavior of the new injector and the fear of fault reactivation, it was decided to re-complete an injection well by isolating the area near the fault it was intersecting. This was achieved by setting bridge plugs to isolate existing zones and re-perforate a new zone above the plugs. The original consideration to recomplete the well in 2008 was to use a conventional coiled tubing unit to access the horizontal section of the water injector. Due to the small size of the platform at this well, there was not sufficient space for placement of coiled tubing surface equipment, a dedicated barge equipped with catenary system had to be considered. Total cost and anticipated risks were high and as such, recompletion of this water injector well by way of a conventional coiled tubing unit had to be classified as low priority due to limited barge time allocated in the 2008 coiled tubing intervention campaign, which naturally became non-feasible and non-viable to execute.

An unconventional method of recompleting the horizontal water injector purely on electric wireline and wireline tractor was then considered and evaluated in 2009, in terms of technical do-ability, economics and risks involved. Recompletion of the water injector was then executed successfully in the same year purely on electric wireline on a shore-offshore-shore daily tripping arrangement at one fourth of the originally anticipated cost when compared to a barge involvement. Successful re- activation of the water injector well realized a significant increase in reservoir ultimate recovery as well as oil gain over the following years of production from the H sand.

This paper will describe the background of the project, recompletion concept selection and well delivery process, actual execution and result of operations. The identified key success factors are also discussed.
Calibration of Permeability Vertical Profile with Regard to Well Production Data
Authors: Khasanov M. M. , Toropov K. V. , Lubnin A. A.
Published: February 2011

A new method for determining permeability profile in producing wells is proposed in this study. The method is based on integration of log interpretation results with well test data and information on vertical reservoir heterogeneity, determined from core studies or production data. Mathematical problem which has been stated is in determining a relationship between true and log-based permeability assuming that the type of permeability distribution function is given. We propose to solve this problem using generalization of the well-known mathematical statistics tool — a quantile-quantile transformation. A new algorithm for determining the Dykstra-Parsons coefficient (as a measure of vertical reservoir heterogeneity) based on historical oil production data is presented as well. The key advantage of proposed technique is acceleration and improvement of history matching in dynamic modeling process. It has been shown that the results obtained after the first model initialization are in very good agreement with production data.
The Oil and Gas Bearing Potential of the North of the Siberian Platform According to the Results of Basin Modelling
Authors: Boldushevskaya Lyudmila N.
Published: February 2011

Two-dimensional modelling of oil-and gas generation history aimed at estimating oil-and gas potential of Paleozoic deposit have been carried out within understudied territory of the north-west of the Siberian platform. The structural imaging data and the results of the geochemical investigations of organic matter such as Rock-Eval pyrolysis, the analysis of the elemental composition of kerogen, the measurements of vitrinite reflectance in coaly inclusions of Upper Paleozoic rocks, the study of biomarker hydrocarbons distribution have been used in the research.

This report presents the results of stratigraphic formation thickness analysis with the use of geological survey, drilling, seismic prospecting data; the results of basin modelling and reservoir properties data analysis. The necessity of further detailed study of oil-and gas accumulation zone, adjoining to the Lama-Khantaika trough, has been founded.

The results achieved make it possible to carry out reconstruction of oil-and gas generation history, estimate resource base and justify the priority directions of licensing within the undistributed fund of the north-west of the Siberian platform.
Application and Optimization of Oil-Based Drilling Fluids for ERD Wells YNAO Area
Authors: Arslanbekov A. , Sevodin N. , Valuev D. , Mosin V. , Korolev A.
Published: February 2011

The paper summarizes application experience and optimization of oil-based drilling fluids for the development of oil and gas condensate fields in the north part of YaNAO area. Key requirements, application criteria, design decisions, advantages and limitations, main features and field application results are analyzed based on Yurkharovskoe oil/condensate field. Extensive computer modeling and hydraulic simulations were performed to take into account temperature and pressure conditions. Actual results are compared to that achieved in the field. The main features of proposed OBM formulation are discussed with respect to local field and reservoir specifics, including wellbore stability, ECD management, reservoir damage, drilling waste management. ERD specific features and benefits are highlighted.

Article demonstrates how extensive planning and preparation work has allowed to overcome many obstacles, typically associated with OBM application in remote areas with harsh climate conditions. Environmental regulations were thoroughly evaluated and proactive waste management was implemented to mitigate environmental risks.

Reservoir conditions and wettability were evaluated to ensure minimum OBM formation damage. Production data is included to demonstrate OBM applicability as reservoir drill-in fluid for oil-wet Yamal reservoirs.

The large scale implementation of oil-based drilling fluids in YaNAO is an ongoing unique project with the massive amount of lessons learned and “know how” technologies involved from all parties. The OBM application experience provided in the paper can assist other companies working in YaNAO with planning and execution of ERD projects and simplify OBM implementation. The experience gained on Yurkharovskoye oil/condensate field can also be applicable to other North Russia projects onshore and offshore.
The Okhotsk Sea Shelf Siliceous Horizon and Sand Reservoir Identification Criteria Based on the Well and Seismic Data
Authors: Bulgakov R. , Zharov A. , Korablinov V. , Krovushkina O. , Tereschuk A.
Published: February 2011

Results of the four exploration wells drilling on the Okhotsk Sea shelf in 2006-2008 had discovered no terrigenous reservoirs in those sections where the sand packages were expected based on the seismic data.
Can Simulation Models Help in Oil and Gas Field Management? An Assessment Methodology for Reservoir Modeling
Authors: Larijani G.R. , Gallivan J.D. , Pepelyaev R.V.
Published: February 2011

The petroleum reservoir is a physical system defined by static and dynamic parameters. It is also an asset requiring investment. The reservoir model is a tool that we use in order to exercise control over the reservoir so that we can produce the reserves economically. By understanding the levels of confidence in our input reservoir parameters and by adopting a controlled approach to using the reservoir model we can strive to get a greater degree of control over the asset.

In this study each reservoir parameter in the model has been scored based on six criteria; Data used in parameter determinationMethodology for parameter computationIndependent verification of the computationEstimation of 90% confidence interval in the resultActions taken to make 90% confidence range smallerPercent decrease of the confidence interval

The Thistle field in the UK sector of the North Sea is used as a reference assessment in this paper.

The assessment methodology presented here can be used by senior technical staff and management to assess the degree of control given by the model before the predictions from the model are used for field development planning. The significance of this methodology is that it provides an objective measure of the quality of a reservoir model. It avoids reliance on intuition and gut feel in establishing trust in the reliability of production profiles and reserves estimates derived using reservoir simulation.
An Efficient Approach for Earth Model Updates
Authors: Suter E. , Cayeux E. , Vefring E. , Næsheim L. I. , Friis H. A. , Escalona A. , Kårstad T.
Published: February 2011

The increased amount of available measurements when drilling with wired pipe opens new possibilities for well placement optimisation. This requires effective interpretation, integration and utilisation of the new information within the timeframe set by the ongoing drilling operation. Earth models carry knowledge about geological structures and physical properties, and form part of the basis for geosteering applications. However, current earth modelling tools have limited capabilities for effective integration of newly acquired information. Model modifications are complex and labour intensive, and the time needed exceeds the time available during drilling. This is a large drawback for decision-making processes that require the most current and precise information.

The complexity of the earth model modification process in existing methodologies is partially a result of storing physical parameters in grids. The grids are controlled by a structural model composed of fault and horizon geometries obtained from geological and seismic interpretation.

We have developed a gridless strategy based on separation of structural information from physical parameters. The separation of the geometric and the parameter models enables modifications to be handled individually and more efficiently. It increases control with model resolution which allows improved management of large data sets, access to earth model information at any scale and efficient sharing over computer networks.

The main principles of our approach are demonstrated through geologically realistic test cases that imitate real drilling scenarios in a reservoir with normal faulting. The combination of new technologies may form a basis for closed loop control/automation of sub processes, required for future automation of the whole drilling process.
Integrated Geological and Engineering Uncertainty Analysis Workflow, Lower Permian Carbonate Reservoir, Timan-Pechora Basin, Russia
Authors: Shirazi A.F. , Solonitsyn S.V. , Kuvaev I.A.
Published: February 2011

This paper aims to show all the steps involved in a rigorous uncertainty analysis study, completed in 2008, in static and dynamic modeling as well as try to highlight some very key steps for a successful study.

Yuzhno Khylchuyu (YK) field is a Permian aged Carbonate reservoir in Timan Pechora basin in European part of Russia. It was discovered in 1981 and has since been appraised by 24 wells. The field is being developed on a regularized waterflood 5-spot pattern with 120-acre well spacing.

The productive reservoir is composed of three main zones, A, B, and C. These zones are not in communication based on geo-chemical data and dynamic well test results. Zone A, which is dominantly progradational has good continuity and best reservoir properties containing 90% of the original oil in place (OOIP). Dominantly aggraditional zones B and C are discontinuous, and have poor reservoir properties.

The motivation behind a rigorous uncertainty analysis on OOIP and Expected Ultimate Recovery (EUR) was due to the large capital investment required for full field development. Thus, the objective of this study was to quantify the range of uncertainty of OOIP and EUR, to identify the most influential parameters contributing to uncertainties in OOIP and EUR, and quantify the impact of those most influential parameters. Such rigorous uncertainty analysis would thus help mitigate the risks with the investment.
Salym Chemical EOR Project, Integration Leads the Way to Success
Authors: Dijk Harm , Buijse Marten A. , Nieuwerf Jan , Weatherill Alan , Bouts Marcel , Kassim Azaitul , Stoica Florentina , Cosmo Claudio
Published: February 2011

The Salym Petroleum Development (SPD) chemical EOR project aims to increase recovery factor by more than 16% by injecting a cocktail of alkaline, surfactant and polymer (ASP). Work to underpin the final investment decision for full field implementation includes a completed single well tracer test, laboratory tests and a planned production pilot. The pilot will help optimize the development by de-risking and reducing unit cost.

This paper will focus on technical aspects - pilot process, options and design approach, and non-technical issues - required integration of design, operations and supplier personnel, and strategic fit.

Technical work to date suggests a phased field implementation, which consists of 4 steps: fresh water preflush, ASP slug, polymer chase flush, and waterflood post flush. Phasing allows the asset to limit water treatment facility investment. Our approach to pilot design and options is to characterize the most important development uncertainties and design the pilot to address them within cost/time budgets. Our work suggests that key uncertainties at Salym are injectivity, lift, scaling, produced fluids handling and fracture growth and most import uncertainties are chemical efficiency, sweep efficiency, reservoir heterogeneity and creating saleable oil.

Key non-technical considerations include the need for integration on an unprecedented scale and ensuring strategic fit. Chemical EOR is a highly integrated business, involving subsurface, engineering, chemical staff and suppliers. Economic success requires affordable chemicals and process efficiency. Due to the unusual nature of this process and its impact on oil field operations, all parties are on a steep learning and integration curve. Shell's portfolio of chemical EOR opportunities, global coordination and shared learnings are allowing Shell and its partners to enter a new era of development and be a frontrunner in this technology.
Analysis of the Impact of an Intelligent Well Completion on the Oil Production Uncertainty
Authors: Grebenkin I.M. , Davies D.R.
Published: February 2011

Oil production is influenced by many parameters, for example the distribution of the petrophysical properties, fluid contacts, relative permeabilities, faults, aquifer strength etc. These parameters influence the production production process in different manners, with every parameter displaying its own, unique, level of uncertainty. This is one reason why the probabilistic approach, which takes into account the major uncertaintiesin the reservoir description and production processes, has developed into an important tool for the prediction of a field's hydrocarbon recovery. This is especially important in the case of heterogeneous reservoirs and horizontal wells. Here, unexpected early water or gas breakthrough into one of the zones will reduce the oil production by preventing oil inflow from other parts of the well.

Intelligent Well (IW) Technology has ability to identify and control the inflow rate at a zone level, preventing the breakthrough of unwanted gas or water. Previous work examined the impact of choking by an IW's Interval Control Valves (ICVs) on the geological uncertainty attributed to the statistical distribution of the formation's properties[l].

This paper extends this study to the “dynamic” parameters (fluid contacts, relative permeabilities, aquifer strength and zonal skin). Each of these parameters exhibit its own uncertainty; with each, individual uncertainty being combined to generate an accurate estimation of overall risk associated with the reservoir's development. The workflow employed will be demonstrated for two cases. This will be followed by an analysis to identify which of the above factors allow the flow control ability of an IW to reduce the production uncertainty in general as well as in specific cases.

The results emphasize the importance of the probabilistic approach for production prediction and illustrate its use as a tool to justify the installation of IW Technology in a particular well. This method will be used for both estimating, as well as reducing, the risks associated with the initial uncertainty of a planned development.
In-Situ Closure Stress on Proppant in the Fracture: A Controversial New Thinking
Authors: Sookprasong P. A.
Published: February 2011

Traditionally, in-situ closure stress on proppant is calculated from minimum horizontal stress minus flowing bottomhole pressure (FBHP, or estimated FBHP). This scenario yields maximum closure stress occurred in the fracture next to the wellbore, and the least closure stresses on proppant are at the tips of the fracture. During fracturing-treatment-design phase, proppant is then selected based on its tested and published strength to withstand this calculated maximum closure stress, hoping that proppant does not get crushed severely or completely.

Results of post-fracture analyses show that most fractures have much lower fracture conductivities and much shorter fracture half-lengths than that of the design values. (Analysis methods and short post-fracture producing time prior to a welltest can also contribute to calculation of lower fracture conductivity and shorter fracture half-length.) There are many factors, such as fracturing fluid's gel residue, formation fines dislodged during fracturing process and fines from proppants being crushed which migrated and plugged part of the fracture during production, actual fracture height being greater than the simulated fracture height, fracture propagated out of pay-zone and not all of proppants stayed in the pay-zone, actual leakoff being higher than the value used for the simulation, etc., that could affect the effective fracture conductivity and fracture half-length.

However, one of the most important factors that may have been overlooked, prior to selecting the proppant for the fracture treatment, is how the in-situ closure stress on proppant has been calculated, i.e., the equation itself.

This paper shows insight of why traditional calculation of in-situ closure stress on proppant may be erroneous, and also shows insight of new value of in-situ closure stress on proppant that should be used for fracture design in the future.
Process Optimization Guidelines in the Design and Operation of Intelligent Water Injection Wells
Authors: Allen Clifford , Ajayi Arash
Published: February 2011

Several challenges are encountered when multi-zone intelligent water injection wells are to be deployed in a field with high contrast in well parameters such as injectivity indexes between individual zones or flow units. Some of these challenges include; selection of a common operating point (tubing intake pressure), estimating effective flow coefficients for interval control valve (ICV) choke settings, determining differential pressures that must be addressed through the ICV choking capability for individual zones and outlining an operations philosophy consistent with the objectives of the well.

Several authors have used Nodal analysis techniques and attenuated Inflow Performance Relationship (IPR) in designing and evaluating the performance of ICVs for single and multi-zone producing and injection wells. This paper combines this technique with sensitivity analysis to estimate flow coefficients for individual zones and investigates which control, surface or subsurface, is most suitable for a multi-zone water injection well for a given sample set of field data.

This paper outlines a number of set points and parametric optimization guidelines that can be used to determine optimal surface and subsurface settings for injection and flow control in intelligent water injection wells. Nodal analysis and attenuated IPR techniques applied to sample field data with high contrast in well zonal injectivity indexes indicates that for a certain range of field values and injection objectives applying only subsurface control (choking zonal ICV) could result in very high pressure drop across zones and cause equipment failure without providing superior injectivity.

Applying sensitivity analysis demonstrates that a blend of well head and ICV control can maintain desired injectivity and result in lower pressure drops that preserve equipment life. Reducing pump pressure typically reduces overall injectivity. Analysis can be extended to cover a wider range of uncertainties such as changes in fracture propagation pressure over time, etc., but these issues are not fully addressed in this paper.
Robust and Cersatile Control Systems to Meet the Challenging Artic Donditions
Authors: van den Akker Jan , Völkel Tobias
Published: February 2011

To control Subsea fields in remote and challenging environments such as the artic, a large amount of system information combined with high availability are key features for a Controls system to succeed. Trying to use traditional power and communication methods, will not meet these requirements, and new ways (robust and versatile) are required.

The paper will describe how to addresses these challenges discussing high speed communication and intelligent power distribution networks. Available field history will be discussed to provide feedback.

High speed communication using fibre optic with or without local copper lines is becoming more and more the standard for subsea communication networks. The available high bandwidth feature provides the large amount of data required to control fields with complex architectures. Combining this with open communication architecture and the appropriate subsea local area network gives third parties direct access to their IP enabled devices, to monitor and actively perform data uploads. This concept is in use as a world wide first application since June 2008 on the BP Taurt Project of the coast of Egypt in the Mediterranean Sea. Further expansion of this field as well application on other projects proves the viability of this concept.

Redundant controlled power distribution (on an AC or DC basis) will provide the functionality to control power distribution to the Subsea Control Modules (SCM). This feature will allow power control to the SCMs on an individual basis. Various scenarios not possible before can now be done: Extension of an existing field whilst the originally installed field can remain in full operation.Installation and retrieval of an individual SCM without interference of the overall field by swapping the power be fore the Electrical Flying Lead (EFL) disconnect takes place.

This feature will also open the possibility to actively monitor the subsea voltages and currents. This information can be used to early detect any abnormal power consumption and confirm the health status of the subsea controls equipment, and provides benefits on overall system reliability/availability required in challenging operating environments such as the artic.
Selection of Decision Variables for Large-Scale Production Optimization Problems Applied to Brugge Field
Authors: Asadollahi Masoud , Nævdal Geir
Published: February 2011

Production optimization has got growing interest in the context of closed loop reservoir management during the last few years. A comparative solution project was designed in connection with SPE Applied Technology Workshop in Brugge, June 2008 (Brugge field). The Brugge field data set is used to investigate a large-scale waterflooding optimization problem. The net present value (NPV) is maximized by updating the production and injection rates of the smart completions. We use a set of history matched models generated by Lorentzen et al. (SPE119101) for investigation of the adjoint based waterflooding optimization. Here a large number of decision variables should be updated to maximize the NPV.

An efficient procedure is employed to handle the high dimensional optimization problem. The procedure starts with two coarse groups of production/inj ection rates over the time, in the beginning of production and at the moment that the cumulative NPV is halved. After a convergence criterion is met, each coarse group is doubled so that the cumulative NPV values are equal over the refined time interval. The procedure continues until the finest update frequency is achieved. The algorithm is applied to the waterflooding optimization task of the Brugge field. The strategy improves the efficiency of initial optimization steps. Moreover, using the new procedure and 168 variables comparable results were obtained as with optimization using 3,360 variables.

Selection of the coarse optimization time intervals for the updating production and injection rates based on the equal cumulative NPV values obtained over the time provides several advantages. First, the strategy decreases the number of the variables tremendously where the large number of optimization variables makes the large-scale optimization algorithms impractical with the current computer resources. Second, larger and faster updates of the rates are made possible as well as achieving higher optimal NPV values for some methods.
Gas-Condensate Recovery For The Low Permeable Sands, Gas Cycling Efficiency
Authors: Kolbikov Sergey
Published: February 2011

The paper reflects problems of gas-condensate recovery for the low permeable sands based on laboratory and analytical PVT analysis and 3D modeling approaches.

Gas-condensate recovery factor (CRF) for the gas-condensate fields depends a lot on initial CGR, filtration properties of the reservoir, well spacing and completion, development plan, economical indexes and final (abandoned) reservoir pressure. High CGR content specific for deep and low permeable zones already determine low gas-condensate recovery factor. On other hand, low permeability leads to deep pressure drawdowns and uneven pressure distribution and trigger earlier and bigger condensate losses in the formation.

CRF official approval according to the current Russian regulations is based on the PVT laboratory or analytical data for 100% gas recovery or 1 bar abandoning formation pressure without taking into account reservoir parameters and system of development. At such pressure conditions and without reservoir properties the ultimate approved condensate recovery factors is too high (over 60%) due to evaporation of liquid condensate below the cricondenbara pressure and neglecting condensate drop out around well bore and in the low pressure formation areas. Due to mentioned above factors the actual ultimate CRF is much less than the approved ones that leads to the losses of economical effectiveness of field development.

The paper reflects the problems of gas-condensate recovery for the low permeable reservoirs and the way how to improve it by implementing a gas cycling process for one of the Western Siberian fields with high initial CGR. The main conclusion is made to use 3D modeling for the correct forecast of the ultimate condensate recovery factors and justification of optimal methods to enhance it.
Solution to Unconsolidated Heavy Oil Reservoirs Evaluation Problem in Tatarstan
Authors: Musin K. , Khisamov R. , Dinmuhamedov R.
Published: February 2011

Formation evaluation provides the input data for reserves’ estimation and oil recovery strategy. Usually core analysis and log-interpretation calibrated with core data are the primarily sources of information. If there are some unsolved problems during core analysis stage, both log-interpretation and following estimations and conclusions could be wrong.

We faced with such situation while evaluating properties of weakly consolidated sandstones and un-consolidated sands in Permian formations of Tatarstan Republic in Russia a few years ago. The problems were primarily associated with destruction of the rocks structure during the core recovery. Weight hydrocarbon saturation and grain size distribution were the only properties determined for these formations by conventional core analysis. It was impossible to determine porosity, permeability and volume hydrocarbon saturation which are critical for modeling and reservoir engineering purposes.

Improved non-conventional method of core analysis described in this paper has been applied to solve this problem. The method suggests different approach depending on rocks’ consolidation. Since year 2005 more than 900 meters of core from twenty-three parametric wells were studied using the method proposed in this paper. As a result, necessary correlations for log interpretation have been adjusted. Application of the method allowed reasonable evaluation of the heavy-oil Ashalchinskoye field. The estimation for porosity has been increased from 30% to 34%, and permeability estimates were increased from 300 mD to 1-3 D. The new estimates of the reservoir properties allowed to suggest SAGD method for oil recovery, which otherwise would be uneconomical. The SAGD method is currently being implemented in this oilfield. Thus, the described unconventional core analysis method has proved its efficiency and can be recommended for further usage.
Inline Technology—New Solutions for Gas/Liquid Separation
Authors: Kremleva E. , Fantoft R. , Mikelsen R. , Akdim R.
Published: February 2011

Recently the problem of associated petroleum gas utilization in Russian gas and oil production fields has attracted a lot of attention. According to the Russian Government the new strict utilization requirements as well as high flaring penalties will be applied to the oil producing companies starting from 2014. At the same time, increasing water cut during the well production life is another problem facing the oil and gas operation. Thus, optimal multiphase oil/water/gas flow separation will become vital for Russia for successful oil development and exploitation in the near future.

Inline separation technology can be the new solution to solve the mentioned challenges. Inline separation is the compact separation in swirl pipe segments. In comparison to the conventional vessel-type separation, the inline technology is simple, low-cost, low-weight, has no moving parts, needs low maintenance, easy to install and operate. These features fit the exigent conditions expected in hostile production environments, and suitable to both new fields and retrofit applications.

This paper describes the inline separation technology, including an overview of qualification work and field experiences. The fundamental mechanisms behind these techniques are explained, and recent advances in these methods are emphasized. The paper especially addresses a test program developed for Marlim production site for reservoir support and gives an excellent example how inline technology can be used to make step-change improvements to the gas, oil, and water management.
Effective Strategies in Development Heterogeneous Gas Condensate Carbonate Reservoirs
Authors: Al-Anazi Hamoud A. , Al-Baqawi Ahmad , Aziz Ahmad Azly , Al-Kanaan Adnan A.
Published: February 2011

A gas bearing carbonate reservoir has been under development in Saudi Arabia to exploit the nonassociated gas to meet the robust increase in gas demand. Initial penetrations showed reservoir heterogeneity with several gas-water contacts (GWCs), variation in reservoir pressure, presence of faults/channels, and H2S content and condensate yield. All these factors made it hard to meet the target developmental plans with conventional reservoir exploitation techniques. Therefore, several delineation wells were initially drilled to assess reservoir boundaries and resulted in an upside potential increase in reserves. Gas producing wells were placed based on calibrated 3D seismic impedance and simulation runs. Several strategies have been used to drill these wells targeting the best reservoir development, such as dual lateral, geo steering, horizontal and extended reach wells. Other technologies like multistage horizontal fracturing and underbalanced coiled tubing drilling (UBCTD) were so effective to enhance the wells' productivity from poorly developed and tight reservoirs. One main obstacle was to drill wells in populated areas and finding a more reasonable surface location that provides the most cost-effective drilling operations. This paper will address all these challenges been faced during the initial field development and the technologies and methodologies been used to achieve full field development and meeting the target gas production. Several field cases will be discussed in detail covering geological interpretation, simulation runs, drilling/completion operations, stimulation, production performance, and reservoir management. These strategies were found so effective in developing this gas field, that they are currently being implemented in other fields that will be put on production during the incoming business plan cycle. These strategies helped to confirm field boundaries, identify multiple GWCs, avoid areas dominated with water encroachment, optimize reservoir depletion, and extend production plateau.