bluuebunny/crossref_metadata_2025_split huggingface dataset:
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.
Some Features of Capillary - Gravity Equilibrium in Layered Strata
Authors: Rublev A. B. , Prohorov A.Y. , Federov K.M. , Shevelev A. P. 
Published: February 2011

Sometimes common determination of water/oil contact in a reservoir is not a trivial objective. For instance interpretation of logging data for Umenskoe oil field gave the anomalous distribution of oil saturation in J2 reservoir. The middle part of the reservoir between 22 and 50 m has the largest value of oil saturation. The reservoir is significantly heterogeneous, the averaged depth distribution of water saturation and permeability are presented on the fig. 1. The highest oil saturation correlates with a middle permeability of the reservoir. That is why the analysis of capillary-gravity equilibrium in layered reservoir was performed.
The equilibrium condition is characterized by fluids immobility and leads to the equation for pressures definitions [2, 5]: (1)Po-Pw=pc=(ρw-ρo)gz+Const
where Po, Pw - are water and oil pressures, pc - capillary pressure drop, g - gravity constant, z - vertical coordinate, pv, po - water and oil densities.
Capillary pressure drop is defined through the dimensionless Leveret function [3]: (2)pc=J(S)σcosθk/m
where σ - is the interfacial tension coefficient, Θ- wetting angle, к - permeability, m - porosity, J(S) - Leverett function; S - water saturation. In the equation (2) the expression in the denominator determines the averaged pore radius.
All laboratory results on capillary pressure investigations (there were seven experiments) were processed to determine a Leveret function. The final results are given on the fig.2. As it is shown the classic presentation of capillary functions is a reliable techniques, there was only one correction: the index in denominator is slightly less than 0.5. й взгляд, распределениям водонасыщенности в пласте.