bluuebunny/crossref_metadata_2025_split huggingface dataset:
Simulation of a Complex Fluvial-Deltaic Reservoir to Identify Opportunities to Improve Oil Recovery in a Mature Oil Field: A Case History
Authors: Urdaneta M.C. , Angel F.J. , Askoul Y.E. , Guevara J. , González E.R. 
Published: February 2011

Abstract
A meandering system where sandbodies produced are complex, so that fluvial deltaic reservoir consist of channel belt sandbodies with highly variable permeability patterns pose a significant challenge for further development of a mature oil field in the Southwest Venezuela. To obtain an optimal strategy a multi-disciplinary reservoir characterization study was carried out.
This study combined all available data (geophysics, geology, petrophysics, and engineering) into a 3D stochastic geo-model to build a reservoir simulation model, many sensitivities with grid size and reservoir description in fluvially dominated deltaic facies were undertaken. These sensitivities included various assumptions on sand content of main producing horizons, sandbody dimensions, permeability distribution, and continuity of flood plain acting as vertical barriers in some reservoir areas.
All these sensitivities were tested during history matching as alternatives to reach a history match. Drilling locations and some exploitation strategies were made in order to improve the oil recovery factor through closing some wells for several periods (3 months - 6 months) and then opening those wells, this technique helped to decrease the water production rate and increased slightly the oil production rate. The associated economic evaluations were based on simulated forecasts while connected volume calculation was made for the chosen realization.
Experience of Commercial Hydrocarbons Forecasting in Pre-Jurassic Series of Western Siberia Region
Authors: Shkurakov V. , Groman M. 
Published: February 2011

Abstract
This particular study has shown high efficiency of the Recog-12 seismic data geological interpretation technology to solve the problem of forecasting oil and gas accumulation zones in the pre-Jurassic series of Western Siberia region and forecasting “commercial inflow” as well.
Wellbore Dynamics of Acid Gas Injection Well Operation
Authors: Mireault R. A. , Stocker R. , Dunn D. W. , Pooladi-Darvish M. 
Published: February 2011

Abstract
This paper presents insights gained from analyzing and modeling acid gas (H2S and CO2) injection well performance over the last 13 years. As the world increasingly develops oil and gas reservoirs that contain significant concentrations of H2S and CO2, the number and size of acid gas injection facilities and their associated acid gas injection wells will increase. A methodology to estimate wellhead operating pressures satisfies a key requirement for design of the injection wells and sizing of the acid gas injection compressors. It may also help inform engineering and operations personnel, and regulatory agencies, of the complex behaviour of acid gas injection wells.
The initial impetus for this work was an operator who increased the acid gas injection rate on a well yet saw virtually no change in wellhead operating pressure, which is inconsistent with water injection well operations. To predict wellhead pressures, a numerical simulation model integrates a modified Peng-Robinson equation-of-state for fluid phase behaviour with a wellbore model and a multi-step adaptation of the Cullender and Smith method to account for the friction and hydrostatic pressure changes associated with flow in the wellbore.
Pressure gradients in aquifers or reservoirs suitable for acid gas sequestration may range from a normal hydrostatic gradient to extremely sub-normal in depleted hydrocarbon reservoirs. Two injection cases present wellbore pressure profiles for injection into a depleted and a normally pressured reservoir at rates of 20, 100 and 280 103m3/d. Three sensitivity studies illustrate the impact of bottomhole sandface pressure, fluid composition and wellhead temperature on wellhead pressure. Depending on conditions, injected acid gas may undergo phase transitions from a gaseous or two-phase mixture at the wellhead to liquid at the sandface and back to gaseous or supercritical out in the reservoir. The complex interactions between temperature, phase behavior, fluid density and pressure can lead to unusual operating characteristics including an increased injection rate or sandface pressure with little or no change in wellhead pressure.
Fast Semianalytical Layered Geomechanical Model Applied to a Parametric Study of Hydraulic Fracture Reorientation in a Water-Flooded Field
Authors: Chertov M. , Siebrits E. , Butula K. 
Published: February 2011

Abstract
Mathematically formulating and implementing a semianalytical-layered geomechanical model by simplifying assumptions about field configuration and properties allows fast numerical estimation of production-induced displacements and stress changes in a reservoir. The developed fast semianalytical model was applied to a parametric study of hydraulic fracture reorientation in a water-flooded field in western Siberia. Results of the study indicate that for the typical conditions in the field, the perturbation of pressure induced by the injection pattern is sufficient to initiate considerable rotations of hydraulic fracture planes. The angle of rotation is very sensitive to anisotropy of initial stress; thicker pay zones result in larger swing angles. This software tool is fast, both in terms of calculation time and time required to set up a numerical task, and is very convenient for preliminary quick-look studies before constructing a detailed 3D reservoir model. The speed of the software tool makes it applicable for parametric, optimization, or sensitivity studies, which require multiple trial simulations in a reasonable amount of time.
Drilling-Derived Rock Strength Can Simulate Upcoming Well Performance
Authors: Fazaelizadeh M. , Rashidi B. , Hareland G. 
Published: February 2011

Abstract
A drilling simulator has been used during the past four years to improve the drilling performance in Western Canada. Rate of penetration improvement and subsequent cost and time reductions are the key elements for drilling these wells. A drilling simulator is required to generate the "Apparent Rock Strength Log" (ARSL) using available offset well data. The ARSL calculation is based on using inverted Rate of Penetration (ROP) models for different bit types, reported bit wear, lithological information and pore pressure in addition to the drilling parameters. The generated ARSL can be modified and correlated for different and new formation tops for planned wells.
The obtained ARSL logs for the wells in the same field have shown an acceptable overlay for the common lithologies using different bit runs and drilling parameters. Furthermore, it can be shown that the ROP match with the new simulated ROP in the same well applying another well's drilling parameters once their ARSL are adjusted. It has been shown that a typical cost reduction can be achieved for the planned wells utilizing the drilling simulator when previously drilled wells exist. The effect of using the combination of different bit runs and drilling parameters can also be explored through use of the simulator. In this paper, a study was conducted for two wells in an Albertan, Canada field to investigate the effect of using the bits used in a well to reduce cost and optimize the next well.
The ARSL logs of two wells were separately obtained and compared. The comparison between the new simulated ROP for the first well, using another well's drilling data, and the available ROP for the second well is also discussed. Final results are showing an acceptable match obtained for ROP values as well as for the corresponding drilling time and final bit wear status in each of the bit run sections. Utilizing the simulator in these type wells shows a significant cost and time reduction potential and can be helpful to apply in preplanning analysis for new wells to be drilled using previously utilized bit types and designs.
Piltun ‘Sub-Arctic’ Offshore Integrated Oil and Gas Development
Authors: Shlyakhova Anna , Kasumov Timur , Jones Malcolm K. , Morgan David 
Published: February 2011

Abstract
The Piltun integrated oil and gas development is a part of the Sakhalin-2 Phase 2 project, and provides a significant portion of Sakhalin Energy's annual revenue through the development of the Northern part of the massive Piltun-Astokhskoye field. This offshore field was discovered in 1986, off the coast of Sakhalin Island, in Russia's Far East. This remote field is in an environmentally sensitive area with an extreme “sub-arctic” climate and a history of seismic activity. The easier part of the field (“Astokh”) was developed first with seasonal production, making it Russia's first offshore oil development, but the multilayered Piltun area retained a significant degree of uncertainty and required a different development approach. First oil was achieved in 2008 and within one year the development produced its 10 millionth barrel of oil, and was benchmarked as “best in class” on drilling performance and recorded a number of “firsts” in the Russian Oil and Gas Industry with its initial smart water injector well.
This paper provides an overview of the challenges of developing this field, the successful reduction of major uncertainties and the multi-disciplinary approaches and use of technology that ensured an extremely successful first start-up of operations.
Results of New Drilling Technology Application on the Development of Verkhnechonskoye, a Complex East Siberian Field
Authors: Wilson K. , Shokarev I. , Small J. , Akhundov E. 
Published: February 2011

Abstract
This paper will describe results of the application of new drilling technology on the well cycle time and production results in the Verkhnechonskoye (VC) Field - one of the largest fields in Eastern Siberia (estimated &gt;200 million tons of oil reserves) with TNK-BP & RosNeft as VCNG's main (company operator) stock holders.
The Drilling & Production environment in the VC field is very challenging, drilling encounters a range of issues from, low ROP in hard dolomites, risk of stuck pipe in unstable shales, high stick'n’slips, to unpredictable BHA behavior in hard gravalite zones, these challenges are compounded by the complex geology of this hetrogenous field. To meet the FDP schedule of 500+ horizontal wells (during 2007-2021) and the production targets (up to 10 million tons of oil per year) it was necessary to significantly improve the well construction time and maximize the net to gross pay ratio of the horizontal section.
VCNG drilling department partnered with Schlumberger and over a period of 24 months completely redesigned the drilling programs and data acquisition methods. The subsurface team developed a methodology to significantly improve drilling efficiency using Schlumberger Rotary Steerable Systems. While the net to gross of the horizontal sections was improved by utilizing high tech Logging While Drilling tools and Geosteering the well to overcome the geological uncertainties.
The initial well cycle for a development well completed using positive displacement motors and standard directional techniques averaged 63 days. The horizontal section of the well was exhibiting a net length to gross reservoir exposure of approximately 30%. By July 2010 the well construction cycle was reduced to 22.3 days including an addition 100+ m of lateral section and the net to gross was 70+% with corresponding higher production.
These latest drilling benchmarks and lessons learnt from one of the first major development projects in the heart of Eastern Siberia will be reviewed in this paper. Information on the basis of well design, the theoretical drilling limit, and the application of drilling technology coupled with information on work processes and best practice will be pertinent to other Eastern Siberia development projects.
Remedial Cementing at High Temperatures (Case Study: Oilfields of Rosneft-Stavropolneftegaz)
Authors: Sakhan A.V. , Chegodaeva A.A. , Gorbunov V.V. 
Published: February 2011

Abstract
Oilfields of Rosneft-Stavropolneftegaz have basic distinctions, such as high reservoir temperatures, up to 1600C, and low depths, down to 3,500m, and old casing strings, where cement sheath is often absent, which require application of special technologies and compounds to be efficient for these conditions.
In prior years all remedial cementing in Rosneft-Stavropolneftegaz, irrespectively of water trouble sources, were executed with cement slurry only. We have selected technologies and compiled application matrices for elimination of behind-the-casing flow (reverse cementing) and flow string leaks (flow string leak repair) in high temperature environment.
In 2008-2009 the laboratory and pilot testing of technologies was performed, and new process was tested during water inflows elimination in the wells with high injection capacity. The risks are determined for planning and execution of remedial cementing, and the ways of finding solutions are offered.
In general the total success of remedial cementing in 2009 in Rosneft-Stavropolneftegaz amounted to 70%, which twice exceeds this index for the year 2008. The average growth of flow rate for 11 wells amounted to 24 tones/day. It was possible owing to: Correct selection of candidate wells;Opportunity to select various plugging materials for specific task, i.e. using materials other than cement slurry;Selection of optimal flow charts for cementing process execution.
The successfully tested technologies are potentially applicable within the Company in 130 wells in the fields of Rosneft- Stavropolneftegaz, Grozneftegaz and Dagneft.
The Research of Influence Sea Stationary Platforms Structure Features on Strength Properties of Basic block
Authors: Guseynova N. I. , Guseynov I. Q. 
Published: February 2011

Offshore stationary platforms for oil gas and recovery (OSP) are established on a continental shelf of the seas and oceans. In Azerbaijan wide development of sea oil fields on Caspian Sea has begun in the late forties with a construction of sea platforms and the individual island bases around "Neft Dashlary" and the "Gurgjany-sea".
Design OSP is possible to be classified to following features: on conditions of basing – pile, gravitational, pendular; on a material - metal, ferroconcrete, combined; on type - through and continuous. Now, on Caspian Sea the most widespread are OSP of pile design.
The basis pile OSP represents an underwater bearing spatial trellised design from the metal tubular elements, attached to a sea-bottom by means of piles. Piles provide perception of all external influences: waves, currents, a wind and operational loadings. Attached by means of piles to a sea-bottom the tower supports an artificial islet on which a derrick, workshops, a helicopter platform, premises and so forth are placed That, as a rule, are the unique expensive constructions reaching of depths 200 – 300 m and more, at width of the basis of an order of 70 m. Cost them, beginning approximately with depth of 60 m, grows proportionally to a depth square exhausting. And, cost of operational platforms with the equipment at development of deep-water deposits can make 50-60 % from an overall cost of arrangement of all deposit.
New Solution: Operational Field Control of Pipelines Corrosion Rate
Authors: Sukhnat Egor 
Published: February 2011

The key target of pipelines operation in oilfields is their failure-free service throughout their useful life. According to Oilfield Pipelines Integrity Strategy, inhibitors are said the main corrosion control solution. The amount of inhibitor-protected pipelines keeps growing across TNK-BP from year to year thus allowing the Company to considerably reduce the pipeline failure rate.
Corrosion monitoring is an important tool of inhibition efficiency tracking. It identifies changes in corrosion rate and other parameters that characterize aggressive effect of the medium. By doing so, corrosion monitoring signals of the changes in pipeline operating conditions or the variances in inhibition processes. Corrosion monitoring confirms that as a result of inhibition, pipeline corrosion rate stays acceptable and poses no threat to pipeline integrity.
Corrosion driving factors are too many and, thus, it seems impossible to find any good-for-all method to forecast pipeline integrity or assess efficiency of the activities performed. The operational methods of measuring corrosion rate and its changes in time are the most informative which makes them more widely used in corrosion monitoring.
Well Path Design Optimization Under Geological Uncertainty: Application to a Complex North Sea Field
Authors: Schulze-Riegert Ralf , Dong Ma , Heskestad Karl L. , Krosche Markus , Mustafa Hassan , Stekolschikov Konstantin , Bagheri Mohammad 
Published: February 2011

Abstract
Well placement and design under geological uncertainties represents a major risk for field development processes. Recent enhancements in geological modeling tools allow reservoir geologists to generate large numbers of alternative 3D models which honor available log and seismic data. For subsurface engineers such models behave quite differently which will impact well design and field development scenarios. Including alternative geological realizations in a manually optimized development plan has proven to be cumbersome and very time consuming. In practical cases, a single reference model is often used as a basis for the dynamic model which creates a major risk of underestimating static uncertainties.
This paper presents a workflow for well path design and optimization under geological uncertainties. Well path screening methods are developed for fast evaluation of alternative well designs in a heterogeneous reservoir model. The method is applied to horizontal well designs including multiple design points for a trajectory honoring geological and technical constraints.
The introduced workflow is capable of handling a large number of design options. Efficient parameterizations of well design parameters in target regions are chosen to limit the introduction of constraint handling methods. Static and dynamic simulations generate performance indicators. A performance overview is supported by the application of experimental design techniques and optimization processes for this study are supported by evolutionary algorithms. Alternative geological models are included in an integrated approach to generate risk profiles representing geological uncertainties.
The workflow is applied to a North Sea condensate field which has two main formations of interest. Information from an exploration well indicates that the uncertainties are related to sand connectivity and net sand content. The specific objective of the case study is to find optimum well positions and designs for horizontal wells by maximizing cumulative gas production. All well candidates are evaluated on the basis of three risked geological realizations which represent a base-, conservative- and optimistic case.
A well screening and well production optimization workflow is developed and successfully applied to complex well designs. Practical experience in a real field application underline benefits for generating risked cumulative production profiles in an extended risk assessment.
Independent Verification of Safety Critical Elements
Authors: Marty Julien , Theys Sophie , Bucherie Christian , Bolsover Andy , Cambos Philippe 
Published: February 2011

Abstract
The main objectives of “Independent Verification of Safety Critical Elements” are to help substantiate that current oil and gas best practices are used, to provide assurance that facilities have been designed to operate safely throughout and to ensure that all Health Safety and Environment risks have been managed to acceptable / As Low As Reasonably Practicable levels. It anticipates the lack of applicable laws or standards, especially in the case of new environments. This approach, which was initially introduced in the United Kingdom after Piper Alpha disaster in 1988, is now becoming an industry standard worldwide.
Offshore Russia offers extreme (remote and arctic) conditions which are a challenge today. This, and the lack of Russian Federation laws applicable to the control of Major Accident Hazards, may represent an issue regarding Health, Safety and Environment for operating companies.
This paper will describe the history of independent verification, and particularly show its application on the Front End Engineering Design stage of a project lead in Russia. It will highlight the regulatory differences and the value of a goal setting process in such situations. This article shows an example of implementation in a country unfamiliar with independent verification.
A New Technology for Filter Cake Removal
Authors: Rostami Ameneh , Nasr-EI-Din Hisham 
Published: February 2011

Abstract
Horizontal and maximum reservoir contact (MRC) wells are intended to increase productivity and minimize water production due to water conning. Their complex geometry makes cleaning up of drilling fluids filter cake a difficult task. It is hard to distribute the acid uniformly over long horizontal sections. Poor acid distribution occurs during matrix acidizing. Coiled tubing cannot reach the total depth of the well because of some limitations such as large washouts, length of the reel and diameter of the coil, which make acidizing horizontal wells ineffective. Available chemical methods of removing filter cake like mineral acids, esters, oxidizers, chelating agents, and enzymes are limited at certain conditions.
This paper introduces a new method for filter cake cleaning using a self-destructing water-based fluid to drill long horizontal and MRC wells, which results in higher productivity. This fluid is a water-based mud that is weighted with calcium carbonate and has both functions of drilling and completion fluids, can reach total depth of MRC wells. It has the ability to effectively stimulate the whole horizontal sections after drilling. This can result in significant cost savings by elimination of acidizing using coiled tubing or any other means and improvement in filter cake removal and thus enhances performance of the treated wells.