bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Novel Wireless Solution to Address Uncertainties in Reservoir Connectivity
Authors: Champion B. P. 
Published: December 2007

AbstractReservoir connectivity is a common uncertainty when considering any new field appraisal or development options. Having a better understanding of reservoir connectivity provides significant benefits in optimising the field development plan. By the application of a new wireless telemetry technology, it is now possible to cost effectively gather high value reservoir connectivity information in situations that previously may have been considered technically impractical or commercially non-viable.Consider for instance, the situation where an appraisal or step-out subsea well is drilled close to an existing producing field, or a new field under development. Today, these appraisal wells are typically permanently abandoned after logging and testing without obtaining any long term pressure data, thus losing a valuable opportunity to gain a better understanding of connectivity in the reservoir and thus prove the reservoir model. Using existing technologies to acquire such data, whilst technically viable, is typically not a cost effective option, requiring either well intervention or high up-front capex. By installing a battery powered wireless telemetry system in the well at the time of well abandonment, but without in any way compromising the integrity of the abandonment, it is now possible to acquire high quality reservoir pressure and temperature data for periods of up to 2 years and beyond. Data from the abandoned well, is transmitted from reservoir depth to the seabed using wireless technology, where it is stored for subsequent collection, on demand, by a supply vessel passing overhead.The paper will review prior methods used for long term reservoir appraisal monitoring and demonstrate how advances in wireless telemetry technology now enable critical information about reservoir connectivity to be obtained from suspended/abandoned wells or zones, where previously there was no cost effective means to do so. It will describe several applications of how the wireless technology has been, or will be applied for the purpose of gaining a better understanding of the reservoir model.
Big Bore Completion and Sand Control for High Rate Gas Wells
Authors: Bourgeois Alain , Bourgoin Sebastien , Puyo Pierre 
Published: December 2007

Abstract
This paper outlines and discusses the issues surrounding the TOTAL AUSTRAL Carina and Aries field development project and the engineering issues addressed to facilitate achieving the project goals of producing gas at high rates from the shallow unconsolidated sand stone reservoirs.
The main challenge in terms of completion architecture was to maximize the well head flowing pressure while insuring "long term integrity" of wells. This was addressed through implementation of limited - or even not - proven technologies.
Application of an Integrated Approach for the Characterization of a Naturally Fractured Reservoir in the West Siberian Basement (Example of Maloichskoe Field)
Authors: Pinous O. , Sokolov E. P. , Bahir S. Y. , Zellou Abdel M. , Robinson Gary , Royer Ted , Svikhnushin N. , Borisenok D. , Blank A. 
Published: December 2007

Abstract
The Maloichskoe field is located in the southeastern part of the West Siberian basin in Novosibirsk oblast (Fig. 1). It was the first field in the basin where commercial oil was produced from the Paleozoic basement. The reservoir consists mostly of limestones and dolomites that are intensively fractured and contain numerous vugs in some zones. The reservoir properties of the matrix are generally negligible, and the production potential of wells is mostly associated with natural fractures and vugs.
The presented study was our first project in Russia where a complete integrated approach was implemented to properly characterize a fractured reservoir. The approach included the following tasks: 1) Identification of fractured intervals in wells using a special technique of BKZ logs processing, 2) Spectral imaging and high-resolution inversion of the seismic data, 3) structural analysis of the field, 4) construction of the reservoir properties model, 5) construction of the fracture distribution model using the Continuous Fracture Modeling approach (CFM).
The final geologic model served as a basis to select the locations for the new wells. The new locations were proposed in the zones with the most intensive development of a network of natural fractures (according to the model). The drilling was associated with significant losses of drilling mud that was an indirect indication of presence of significantly fractured zones. The wellbore image FMS that was recorded in the well, showed a good level of correspondence between the model forecast and the actual result. The well contains interval of numerous fractures and large vugs. Eventually, the well showed a good production results and currently is one of the best producers in the field.
As such, we recommend application of the described integrated approach for modeling complex fractured reservoirs in the other fields of Russian Federation.
Hydraulic Fracturing and Filtration in Porous Medium
Authors: Smirnov N. N. , Kisselev A. B. , Nikitin V. F. , Zvyaguin A. V. , Thiercelin M. , Legros J. C. 
Published: December 2007

Abstract
The practical problem arises in enhancing oil recovery and is relevant to hydraulic fracturing process and subsequent frontal displacement of fluids from subterranean environment. Entrapment of residual fluid by the displacing one lowers down the displacement quality leaving most of residual viscous fluid in porous matrix.
The present paper provides the data on hydraulic fracture simulation accounting for accumulation of damages in elastoviscoplastic medium, as well as the effect of inhomogenity of porous media properties on fracture propagation. After hydraulic fracture formation terminated the cleanup procedure begins. Fracturing fluid is evacuated from the well and fracture being displaced by the oil and gas flow under the influence of pressure differential. The quality of fracture cleanup determines in the long run the effectiveness of oil recovery measures. Fracturing fluid being left entrapped in the fracture decreases its effective oil collecting area. Thus stability and quality of displacement of fracturing fluid is of key importance to provide free way for the oil and gas flow.
However, in frontal displacement of a more viscous fluid by a less viscous one from porous medium by applying pressure differential the Rayleigh-Taylor or Saffman-Taylor instability of the interface could bring to formation and growth of "fingers" of gas penetrating the bulk fluid. The growth of fingers and their further coalescence could not be described by the linear analysis. Growth of fingers causes irregularity of the mixing zone.
The present study investigates analytically, numerically and experimentally the instability of the displacement of viscous fluid by a less viscous one from porous medium and evaluates characteristic size of entrapment zones. Both miscible and immiscible displacement was investigated. Extensive direct numerical simulations allowed to investigate the sensitivity of the displacement process to variation of values of the main governing parameters.
Taking into account non-linear effects in fluids displacement allowed to explain new experimental results on the pear-shape of fingers and periodical separation of their tip elements from the main body of displacing fluid. The effects of porous medium inhomogenity on the instability of fluids displacement were investigated both numerically and experimentally. It was demonstrated that definite inhomogenity could essentially stabilize displacement.
Riserless Mud Recovery (RMR) System Evaluation for Top Hole Drilling with Shallow Gas
Authors: Frøyen Johnny , Rommetveit Rolv , Jaising Hitesh , Stave Roger , Rolland Nils Lennart 
Published: December 2007

Abstract
The Riserless Mud Recovery (RMR) System is a new and emerging technology for top hole/open hole drilling. The technology is planned to be used in Russia in 2006. The RMR Technology is applied for the open hole sections (no BOP installed), enabling return of fluid and cuttings in a closed system. A subsea mud pump is returning mud and cuttings to the drilling rig for treatment/recirculation instead of dispersal on the seabed. Since weighted mud is used the risk of shallow gas influx is reduced compared to conventional top hole/open hole drilling. However, since the return is routed to the platform, shallow gas is a cause of concern.
A new transient coupled reservoir-well two phase well control simulator for modelling drilling and well control scenarios with a dual pump drilling system has been developed.
The paper describes the RMR System and its potential related to shallow gas detection and control compared to conventional top hole drilling.
Shallow gas scenarios during top hole drilling with the RMR System have been simulated and the results evaluated. The focus has been to detect a kick before gas reaches the return line. The evaluations have confirmed that the RMR System is a safe system, which can detect a shallow gas influx prior to gas reaching the return line, and also handle the influx in a safe manner. Modelling further shows that pit gain, sub sea power and RPM of subsea pump are the main parameters for kick indication. These results verify the feasibility of the RMR System related to safety and well control. In addition this System will reduce discharges to sea during top hole drilling, as well as significantly reduce the frequencies of shallow gas incidents.
A New Cement Developed for High-Temperature Sidetracks
Authors: Al-Yami A. , Jennings Scott , Nasr-El-Din H. A. , Khafaji AbdulKarim , Al-Humaidi Ahmed 
Published: December 2007

AbstractDirectional drilling makes it possible to drill multilateral wells into different parts of a reservoir from a single wellbore. Many directional wells are drilled to reach reservoirs inaccessible from a point directly above because of surface obstacles or geologic obstruction. Wellbore sidetrack drilling operations with hard cement plugs have been used for years. Placing cement plug in the borehole and allowing the cement to develop high compressive strength perform sidetracking technique. The hardened cement plug when drilled deflects the bit away from the current borehole, starting another open hole section.Conventional cement formulations for sidetrack kickoffs usually fail when the ROP (rate of Penetration) for the cement plugs is much more than the ROP in the formation Sidetracking failures, in building up kickoff angles, results in operation delays and cost overrun. High compressive strength cement system with slow ROP should be designed and developed specifically for side tracking operations.A rate of penetration device helped optimizing cement formulations to determine the ROP through cement plugs. This is done by controlled circulation of drilling fluid through the drill bit and rotating the bit at a fixed load and speed. Different chemicals for buildingup compressive strength were evaluated. Special types of cements were designed and evaluated for possible use for sidetrack kick off plugs. Addition of inert particles to cement and their effect on the compressive strength and ROP were investigated.In this paper, a new system was developed and results in a slow ROP for the use in sidetrack drilling. The performance of this system outstand any known existing cement formulations for side track drilling and has great potential to improve sidetrack angle builds up.
Fracture Treatment Optimization for Horizontal Well Completion
Authors: Soliman M. Y. , Pongratz Reinhard , Rylance Martin , Prather Dean 
Published: December 2007

Abstract
Fracturing has become a viable and important option for completing horizontal wells. There are many fracturing processes and methods to consider for placement fractures. Optimization of the completion process including the number and size of fractures is still a challenge.
Although fundamentally similar to fracturing vertical wells, horizontal well fracturing has unique aspects that require special attention to ensure successful treatment. Differences exist between horizontal and vertical wells in the areas of rock mechanics, reservoir engineering, and operations. These aspects affect the optimization process for successful placement of treatments and optimum asset performance.
In this paper we discuss the various factors crucial to successful completion of a fractured horizontal well. We discuss these factors in relation to both longitudinal and transverse fracture applications. Success factors include the optimum perforation process, overcoming fluid flow convergence towards the wellbore in case of a transverse fracture, and the fluid flow and stress interference between multiple fractures.
The paper presents a field case and laboratory and numerical experimentations illustrating the impact of the various factors on the completion of the horizontal wells and the optimization of the fracturing process.
Sustaining Well Productivity
Authors: Weaver Jim , Nguyen Philip , Ingram Stephen 
Published: December 2007

Abstract
Surface modification agents (SMAs) and their coating onto proppant have been used in thousands of wells in the past 10 years resulting in significant improvement in productivity in terms of production rates and duration. In a recent field study1 involving more than 100 well stimulations, these SMAs were found to dramatically enhance the recovery of aqueous-based fracturing fluids during well cleanup following the fracturing treatments. This paper describes how a simple modification to proppant surfaces resulted in these dramatic post-frac well cleanups and subsequent well productivity. A comparison of laboratory results along with actual case histories will help explain the significant improvement in hydrocarbon production observed in fracture stimulated wells using SMA-coated proppant.
Advanced Technology To Reduce Water Cut: Case Studies From the Pemex Southern Region
Authors: Farrera Romo Gustavo A. , Leyva Héctor Hernández , Aguilar Raúl Bonifacio , Campos Carlos Caballero , Eoff Larry , Dalrymple Dwyann 
Published: December 2007

Abstract
This paper presents the results of a successful application of a new-generation polymeric relative permeability modifier (RPM) that enables treatments to reduce water cut without workover equipment. The new RPM can be bullheaded into open intervals without the need for isolating water zones from hydrocarbon zones. This treatment was applied to several wells in the Pemex southern region. As a result of the treatment, the productive life of the wells has been extended, with a gradual decrease in water cut. These results indicate high potential profitability values for mature fields with high water cut requiring a simple, low-cost treatment without the need for workover equipment or shut-in times. The new treatment can increase the hydrocarbon recovery percentage in sands that in all probability otherwise would be destined for abandonment.
This paper describes the treatment methodology, which begins with problem identification and an understanding of the origin of the water breakthrough. Next, the paper describes the new technology, which uses hydrophobically modified water-soluble polymers and explains how applying such polymers can control water selectively. In addition, the detailed execution of the treatment is described, followed by the very positive production results of the treatment. The results of this low-investment, high-profit technology are very promising for other wells under similar conditions in which workovers with conventional technologies would be cost prohibitive.
Wellbore Stability Study for the SAFOD Borehole Through the San Andreas Fault
Authors: Paul P. , Zoback M. 
Published: December 2007

AbstractThis paper presents a wellbore stability study of the SAFOD (San Andreas Fault Observatory at Depth) research borehole at Parkfield, central California. In the summer of 2005, the SAFOD borehole was successfully drilled through the San Andreas Fault (SAF) in an area characterized by fault creep and frequent microearthquakes. In this study we report how the analysis of wellbore failures in the upper part of the hole, geophysical logs and a model for stress gradients in the vicinity of the fault were used to estimate the mud weights required to successfully drill through the fault. Logging-whiledrilling acoustic caliper data and real-time hole volume calculations both show that relatively little failure occurred while passing through the SAF. Thus, the predicted mud weight was successful in drilling a stable borehole. However, a six-arm caliper log run after drilling was completed indicates that there was deterioration of the borehole with time. We suspect this was caused by failures along the weak bedding planes around the borehole, exacerbated by fluid penetration and key seating.
Applicability of Flow Assurance Solutions for Russian Oil & Gas Developments
Authors: Dykhno L. , Mehta A. , Moiseyenkov Alexey Vladimirovich 
Published: December 2007

Abstract
Over the past decade, flow assurance applications have been extremely successful in many offshore deepwater gas and oil project developments, where the cold ambient sea bottom temperature and water depth pose enormous technical challenges. Flow Assurance encompasses a broad range of technical areas, including management of solids such as hydrates, wax, asphaltenes to avoid blockages in subsea equipment and multiphase transport of produced reservoir fluids to a host facility. The high cost of remediation and limited accessibility for intervention of subsea equipment has highlighted the importance of developing robust flow assurance solutions in such severe operating environments. The operating environment that exists in many Russian gas and oil fields - both offshore and onshore - poses similar technical challenges. This paper notionally classifies Russian fields based upon their expected flow assurance issues and challenges and describes issues that are in common between deepwater production and oil and gas developments in Russia. We also demonstrate the applicability of lessons learnt from the deepwater to Russian oil and gas field production.
Data Richness and Reliability in Smart-Field Management – Is There Value?
Authors: Aggrey G. H. , Davies D. R. , Ajayi A. , Konopczynski M. 
Published: December 2007

AbstractAn essential part of the process to determine the value of advanced wells and fields is the explicit inclusion of the reliability of the various measurement sensors, in particular, and the data collection, transmission and analysis in general, when building the "Value Statement" to justify installation of intelligent wells. The desire for increased intelligence in the monitoring and control systems associated with Intelligent Well Technology (IWT) results in the deployment of more sophisticated and potentially accurate, downhole components of greater capabilities. However, these results in a more complex completion, which can be expected to exhibit a lower reliability than that shown by simpler system.Ultimately, the greater number of more complex components may reduce the equipment reliability to such an extent that the increased chance of failure has reduced the "Value of Information" below that which can be derived from a simpler system. This paper uses a synthetic reservoir to explore and compare the value of extensive, accurate measurements with a higher chance of component or system failure (the "rich data" case) with the deployment of fewer and or lower resolution sensors of greater reliability (the "poor data" case).The value associated with these two cases will be quantitatively compared in terms of a Risked Opportunity Loss. This comparison will illustrate how this workflow can be used to design cost-effective, well completions capable of Real Time Reservoir Management of an Oil or Gas field. The example chosen will also illustrate some of the drivers behind the choice of the optimum completion equipment.
Isolating Unwanted Water Production: The Through-Tubing Inflatable Solution
Authors: Kelbie G. M. , Garfield G. L. , Mackenzie G. R. J. 
Published: December 2007

Abstract
With continual increase in water production from maturing reservoirs comes the expense of installation of surface handling equipment, disposal and environmental concerns and a reduction in production efficiency from hydrocarbon producing wells. These costs run into millions of dollars every year, dealing with this problem. The operators of these wells have utilized differing technologies and procedures in efforts to control production of these unwanted fluids. Water shut-off applications in one way or another are an everyday part of well servicing work. Some of the methods and practices currently used today to help combat this problem include, placement of cements, plugging back the zone with the aid of mechanical isolation devices, pulling the completion and performing work-overs, and the utilization of purposely designed cements or chemical water blocking agents. Initial efforts to utilize such fluids proved encouraging but methods were required by the operators in order to allow accurate placement of these chemicals. Some of the drivers are; Economics, in terms of the relatively high cost of such fluids and;The reaction of such water blocking chemicals when placed incorrectly within producing formations and the inability to reverse engineer such misplacements.
Couple these problems with the well geometry to be worked in and the solution of placement can be seen to involve many diverse complications. For this reason the requirement for innovative through-tubing zonal isolation solutions has never been greater. Through-tubing inflatable technology has, for some time now, been providing high-expansion devices in order to provide our industry with an economical and reliable method of isolating and placing water blocking treatment fluids. In this paper we will focus on current inflatable tools that are available today and how they can be utilized to provide cost effective water shut-off solutions at the source of the problem.
Estimating Klinkenberg-Corrected Permeability From Mercury-Injection Capillary Pressure Data: A New Semianalytical Model for Tight Gas Sands
Authors: Huet C. H. , Rushing J. A. , Newsham K. E. , Blasingame T. A. 
Published: December 2007

Abstract
This paper presents the practical applications of a semi-analytical model for estimating the Klinkenberg-corrected permeability from mercury-injection capillary pressure (Hg-pc) data in tight gas sands. The fundamental relationships between rock pore size/geometry and basic rock properties are well-documented in the petroleum literature. Moreover, since rock pore characteristics can be accurately quantified from interpretation of mercury-injection capillary pressure data, the literature is replete with models for estimating permeability from Hg-pc data. However, existing Hg-pc models tend to yield inconsistent results — and few models have been shown to be directly applicable for low-permeability sands.
The basis of our model is the Purcell/Burdine model (bundle of capillary tubes) combined with the Brooks/Corey model (power law relationship of capillary pressure versus wetting phase saturation). We tested our model using more than 100 sets of mercury-injection capillary pressure data. Effective porosity in our data set ranges from 4 to 14 percent, while absolute permeability ranges from 0.005 to 0.5 md.
The primary technical contribution of this paper is a tuned model for estimating Klinkenberg-corrected permeability from mercury-injection capillary pressure (Hg-pc) data in tight gas sands. The final form of our model allows estimation of the absolute (Klinkenberg-corrected) permeability as a function of effective porosity, irreducible wetting phase saturation, displacement pressure, and pore size characteristics. The model is also reversible — we can estimate a capillary pressure profile from routine permeability and porosity data.