bluuebunny/crossref_metadata_2025_split huggingface dataset:
First Borehole to Surface Electromagnetic Survey in KSA: Reservoir Mapping and Monitoring at a New Scale
Authors: Marsala Alberto F. , Al-Buali Muhammad , Ali Zaki , Ma Shouxiang Mark , He Zhanxiang , Biyan Tang , Zhao Guo , He Tiezhi 
Published: October 2011

Abstract
The first Borehole to Surface Electromagnetic (BSEM) pilot field survey in the Kingdom of Saudi Arabia (KSA) was successfully executed to identify oil and water bearing reservoir layers in a carbonate oilfield water injection zone.
Maximizing recovery factor by means of detailed mapping of hydrocarbon accumulations in the reservoirs is a key requirement for oil producing companies. This mapping is done routinely by accurate measurements of fluid distribution at the wells’ locations, but a knowledge gap exists in the inter-well volumes, where typically only density-based measurements are available (seismic and gravity). Such technologies are not always effective to discriminate and quantify the fluids in the porous space (especially when difference in fluid densities is small, such as oil and water). On the contrary, when high electrical resistivity contrasts exist between hydrocarbons and water, electromagnetic (EM) based technologies have the potential to map the distribution of the fluids and monitor their movement during the life of the field, hundreds of meters or kilometers away from the wellbores.
The objective of a BSEM survey is to obtain fluid sensitive resistivity and induced polarization maps. These are based on an acquisition grid at the surface, a few kilometers around the EM transmitting well, which reveal oil and water bearing zones in the investigated reservoir layers.
In this pilot field test, BSEM showed the potential to map water-front movements in an area of about 4km from the single well surveyed, evaluate the sweep efficiency, identify bypassed/ lagged oil zones, and eventually monitor the fluid displacements, if surveys are repeated over time. The data quality of the recorded signals is highly satisfactory. Fluid distribution maps obtained with BSEM are coherent with production data measured at the wells’ locations, filling the knowledge gap of the interwells area.
Three key R&D objectives for this BSEM pilot are achieved. Firstly, the capability to record at the surface EM signals generated in the reservoir, secondly, the capability of BSEM to discriminate between oil and water saturated reservoir zones, and finally obtain resistivity maps and a fluid distribution estimate plausible and coherent with the information obtained from well logs, crosswell EM, production data and reservoir models.
In addition to reservoir monitoring, BSEM can be very useful in non-diagnosed areas like exploration fields for hydrocarbon exploitations.
First Installation of Alternate Path Openhole Packer Providing True Zonal Isolation in Openhole Gravel Packs
Authors: Hecker Michael T. , Barry Mike D. , Ryan James T. , Ruiz Vicente F. , Stevens Peter , Pedro Nanga , Yeh Charles S. , Inglesfield James 
Published: October 2011

Abstract
Openhole completions are often selected as the preferred completion technique to provide high capacity, low skin completions. With the advances of Alternate Path® Technology (APT), a full gravel pack can be realized under challenging well conditions to provide increased long-term reliability. One draw back to openhole gravel packs (OHGP) has always been the inability to isolate undesirable water or gas, whether it be during the initial completion or during the production lifecycle of the well. Numerous improvements have been made in recent years with openhole packers to provide zonal isolation in standalone screen applications. Unfortunately, not all formations can be successfully completed with standalone screens due to non-uniform sand grain sizes, high concentration of mobile fines, or low hole angle through the pay interval. To achieve the benefits of zonal isolation, operators have opted to either complete the well as a cased hole completion, extend the limits of standalone screens beyond generally accepted best practice guidelines, use expandable screens with isolation, or attempt to seal the openhole annulus with swellable materials after gravel packing. These options may not be optimal and can compromise the ultimate recovery potential of the well.
A new openhole packer with APT, Shunt Zonal Isolation (SZI) packer, has been developed and successfully deployed. When run in conjunction with Internal Shunt Alternate Path Technology (ISAPT) screens, true zonal isolation in openhole gravel pack completions can be achieved. This packer can be run through 9⅝-in. casing, is set before gravel packing begins and forms a seal against the borehole to provide true annular isolation in either round or oval hole sizes up to 10 ¾-in. The openhole annulus above the packer is gravel packed conventionally, then slurry is diverted through the shunt system to gravel pack below the isolation packer. Alternate Path Technology ensures the annular space, both above and below the isolation packer, is completely packed.
A Capacitance-Resistive Model and InSAR Imagery of Surface Subsidence Explain Performance of a Waterflood Project at Lost Hills
Authors: Wang Wenli , Patzek Tad W. , Lake Larry W. 
Published: October 2011

Abstract
Extraction of oil and gas can cause reduction in pore pressure, occasionally resulting - in shallow reservoirs - in subsequent compaction that forms a surface subsidence bowl. In the last 10 years, there has been over 10 feet of subsidence in parts of the Lost Hills diatomite oil field in California (Bruno et al.1992). The surface subsidence at Lost Hills not only causes damage to surface facilities and wells, but also reactivates faults and reduces rock permeability. Subsidence makes reservoir optimization difficult. Hence, it is important to assess or predict the surface subsidence and the reasons for subsidence early in the life of an oil field to make an optimization plan.
We use jointly the capacitance-resistive model (CRM) (Alberoni et al. 2003 and Yousef, et al. 2006) that relies only on injection and production data, and the inSAR satellite imagery of surface subsidence. From CRM simulations, we estimate the connectivity between injectors and producers as well as general water flow directions from individual injectors. We then superimpose well connectivity and inSAR imagery to diagnose the reasons for the subsidence. Using a new surface subsidence model, which is based on the continuity equation of CRM and rock mechanics, we are able to predict the average surface subsidence at Lost Hills from the injection and production rates.
Our work shows that there was significant volumetric rock damage at Lost Hills and the well connectivity changed dramatically with time because of the water injection- and compaction-caused rock damage. We conclude that for a soft, fragile and nearly- impermeable rock such as the diatomite, high injection rate weakens the rock and creates dynamic water flow tubes or ‘channels’ without providing good pressure support to the reservoir. These high permeability ‘channels’ recirculate most of the injected water between the injectors and producers.
Our CRM/inSAR approach is new and gives insights into the time-dependent and spatially variable fluid flow fields in a relatively shallow waterflood. Consequently, we may be able to suggest optimum water injection strategies to enhance oil production, while minimizing rock damage and surface subsidence. In addition, the proposed surface subsidence model is a convenient and reliable way to predict the average subsidence.
Numerical Indicator for Flow Through Heterogeneous Permeable Media
Authors: Ghanbarnezhad Rouzbeh 
Published: October 2011

Abstract
This paper suggests a numerical indicator to examine the nature of miscible displacements in heterogeneous permeable media. We compare miscible displacements through assigning a numerical value to the governing flow regime. Previous studies point out that the competition between effects is the cause of developing various types of flow regimes (dispersive, fingering, gravity override, and channeling). However, the distinction between the flow patterns is only possible qualitatively (visually) so far; therefore, the visual traditional method fails to properly characterize displacements with a similar flow pattern and lacks the capability of evaluating the displacement performance as the flow regime changes.
We adopt the notion of the correlation coefficient function and use the progression of the mixing zone to assign the numerical values to the flow regimes. The correlation coefficient function of the lengths of the mixing zone calculated between two different times represents the tendency to propagate linearly with time. On the other hand, the correlation coefficient function of the squared length of the mixing zone corresponds to linear growth with Time. Using the arithmetic average of the correlation coefficient functions over successive time intervals, we introduce a flow regime indicator to study the nature of miscible floods. We use a simulation approach to validate the numerical indicator. The numerical values assigned to the flow patterns are consistent with the visual identification of flow patterns.
We conclude that the pattern attributed value is an effective measure of the mixing zone development in heterogeneous permeable media for the the limited cross flow. The suggested procedure identifies the type of flow regime at any stage of displacement and helps monitor evolution of the mixing zone. The latter is important in prediction of displacement performance. Through this study, we investigate the relation between the attributed numerical values and the displacement performance.
Modeling Surfactant Enhanced Oil Recovery From Short And Long Fractured Carbonate Cores And Scaling Of Results To Field Applications
Authors: Alamdari Baharak B. , Kazemi Hossein , Salehi Mehdi , Thomas Charles , Izadi Mehdi , Manrique Eduardo 
Published: October 2011

Abstract
This paper presents the results of oil recovery from short fractured and unfractured carbonate cores using a high speed centrifuge. Also, we will provide results of oil recovery in long cores. The short cores are 1.5-inch long while the long cores are 12-inch long. The experiments are designed to decipher contributions from rock matrix in presence and absence of fractures, and for imbibition and gravity drainage oil recovery with and without surfactant. The laboratory results are scaled to field using scaling rules as well as numerical simulation.
The purpose of this research is to demonstrate that surfactant oil recovery can be a viable enhanced oil recovery process in fractured carbonate reservoirs when fracture distribution and connectivity are favorable. Furthermore, these carefully designed experiments improve our understanding of how oil mobilization can be enhanced in fractured carbonate rocks and how the process can be modeled and solved numerically.
The cores were selected from a carbonate outcrop, saturated with brine, displaced with a 22-centipoise crude oil from a specific field, and were aged to promote oil-wetness. A typical unfractured long core had a spontaneous imbibition oil recovery of zero, but produced 2% oil in a 5000 ppm anionic surfactant solution. The long fractured cores had a spontaneous imbibition oil recovery of 21% and a surfactant oil recovery of 38%. The short cores in the centrifuge produced substantially more oil because of enhanced gravity effects. The implication of these results to field applications, and much more, will be discussed in the paper.
We were able to match experimental results using an in-house numerical model, where, we believe, the model's theoretical basis is consistent with the physical principles of fluid flow in porous media. The results of these experiments, and our experience in a major fractured carbonate reservoir, have given us a better understanding of the mechanism of enhanced oil production in fractured carbonate reservoirs by dilute surfactant solution and micellar solutions. We are hoping that the results of this research will promote field applications.
Optimizing Transverse Fractures in Liquid-Rich Formations
Authors: Vincent M. C. 
Published: October 2011

Abstract
Horizontal wells provide the opportunity to initiate multiple transverse fractures and dramatically increase the connection between the wellbore and the hydrocarbon-bearing reservoir. This has allowed the economic development of low permeability reservoirs that cannot be pursued without reservoir stimulation. Our success, however, does not imply that we are optimized.
Recent field results in the Niobrara, Bakken, Viking, Haynesville, Eagle Ford and other reservoirs completed with transverse fractures are yielding answers to many questions, including:
Are we achieving acceptable vertical height growth? What adjustments are necessary to accommodate multiphase flow? What fracture conductivity is needed? How many frac stages will provide the optimal economic returns? Are we effectively stimulating each stage? Are precautions necessary to avoid or reduce overflushing of proppant? Will restimulation of these reservoirs be necessary given current completion strategies?
This paper explains the challenges of accommodating multiphase flow in transverse fractures and summarizes theoretical, laboratory, and field results demonstrating the best practices. Evidence is reviewed indicating that fractures fail to sustain hydraulic continuity through many laminations and techniques are suggested that can improve the ability to drain multiple stacked pay intervals with horizontal wells. Updated production results from the Bakken and Eagle Ford should be of benefit to any operator stimulating horizontal wells that produce significant oil, water, or condensate volumes.
Why Y?
Authors: Williams John M. 
Published: October 2011

Abstract
This paper provides an analysis of a widely-used pressure-volume-temperature (PVT) parameter, demonstrating common errors made in its use and the lack of detailed descriptions in common reservoir engineering texts. Use of the Y-function is a valuable tool for increasing the accuracy of bubble point measurements, and it has other important uses, but its detailed application is poorly understood, leading to unnecessary errors in one of the most fundamental PVT properties.
Best practices have been developed and are presented, to encourage proper application of the Y-function, together with detailed recommendations for setting up Excel spreadsheets to help identify the most precise bubble point, and optimize Y-function values.
More extensive use of the Y-function to obtain bubble points for down hole or surface oil samples is recommended as it could improve quality control and selection of more representative samples.
Scale Inhibitor Squeeze Treatments Selection, Deployment and Monitoring in a Deepwater Gulf of Mexico Oilfield
Authors: Jordan M. M. , Kramer Ted , Barbin David , Linares-Samaniego Sandra , Arnette Walter 
Published: October 2011

Abstract
This paper describes field experience and lessons learned from scale-control operations in a deepwater development in the Gulf of Mexico.
The injection of seawater for reservoir pressure maintenance resulted is a high barium-sulfate scaling tendency upon breakthrough of injection water which meant that it was critical to have effective scale management achieve high hydrocarbon recovery for this field.
Use of conventional, water-based squeezes in the field did not deliver the squeeze lifetime expected and for some treatments resulted in production impairment. Hence, based upon risk mitigation, an alternative scale squeeze program was required this alternative program was supported by an extensive set of laboratory tests including reservoir condition coreflooding, based on these laboratory results it was decided to apply squeeze treatments of aqueous scale inhibitor proceeded by mutual solvent to reduce the risk of relative permeability damage and increase squeeze life by enhancing inhibitor adsorption.
Aspects of well cleaning prior to scale squeeze deployment will be outlined as this has proved critical to the success of scale squeeze treatments in these wells which have an asphaltene tendency.
Results from two of the five current scale squeeze treatments are presented to demonstrate that an integrated evaluation, treatment program design using squeeze design software, implementation and monitor (critical ions, inhibitor residuals, suspended solids) approach can being significant benefit to this challenging aspect of flow assurance.
The paper will explore in detail the issues associated with inhibitor-squeeze treatment selection, deployment, monitoring in deepwater Gulf of Mexico and is a good example of implementation of best-practice sharing from another oil basin (Angola, West Africa) were the same operator overcome similar issues.
Innovative Method of Gas Shale Well Intervention with Coiled Tubing/Jointed Tubing Hybrid String
Authors: McNeil Fraser , Ehtesham Asif , Gracey Paul 
Published: October 2011

Abstract
As the industry strives to maximize production in US shale plays, the number of extended-reach horizontal wells being drilled continues to increase in efforts to optimize reservoir contact and increase fracture intensity. Because operators demand the same level of performance achieved on shallower wells while providing a cost-effective and safe solution, these wells present complex challenges for completion and intervention operations.
Coiled tubing (CT) enables an efficient means to deploy tools and perform pumping operations, such as drilling out plugs, wellbore solids cleanout, and matrix or fracture stimulation in a continuous manner. In any well-intervention operation, the CT size is maximized to achieve the desired level of operational efficiency and effectiveness. To reach the target depth of these extended-reach wells, smaller CT must be used because reel capacity is limited. This not only limits the pump rate that can be achieved, but smaller CT is more susceptible to helical lockup and could require costly assistance to achieve depth. Also, many roadway authorities have established size and weight restrictions that can dictate the size of CT used.
A new hybrid solution is now being used to combine the benefits of both CT and jointed tubing (JT) in a single work string. The solution presents many cost benefits while extending the depth of reach that can be accomplished to perform continuous-pumping operations using the optimum diameter tubing and pipe. The system incorporates unique well-control tools that enable seamless functioning of the string in a live well, thus providing considerable time and cost savings.
This paper presents the benefits of the hybrid unit and discusses the enabling technology while providing an overview of field trials of multizone stimulation treatments in the Bakken and Marcellus reservoirs.
A Comparison of Stochastic Data-Integration Algorithms for the Joint History Matching of Production and Time-Lapse Seismic Data
Authors: Jin Long , Alpak Faruk O. , Hoek Paul van , Pirmez Carlos , Fehintola Tope , Tendo Fidelis , Olaniyan Elozino 
Published: October 2011

Abstract
Quantitative integration of spatial and temporal information provided by time-lapse (4D) seismic surveys to dynamic reservoir models calls for efficient and effective data-integration algorithms. We carry out a comprehensive comparison of stochastic optimization methods using both a synthetic and a field case.
Our first case is a challenging synthetic test problem known as the Imperial College Fault Model (ICFM). Three methods, namely, Very Fast Simulated Annealing (VFSA), Particle Swarm Optimization (PSO), and Neighborhood algorithm (NA) are compared in terms of convergence characteristics, data-match quality, and posterior model parameter distributions. Based on the knowledge developed on the ICFM problem, we isolate VFSA and PSO and further evaluate their performance on a field case involving an offshore West African deepwater turbidite reservoir undergoing waterflooding. The field case has a reasonably long production history and good-quality 3D and 4D seismic data allowing the construction of a geologically-consistent model via dynamic calibration. As such, it constitutes a relevant field test for joint seismic-production history matching. We assess the data-match characteristics and the quality of dynamic forecasts delivered by VFSA and PSO in the field case.
Practical guidelines are developed over the course of the studies for selecting a "fit-for-purpose" optimal method for joint history-matching workflows. Our results show that PSO, a population-based method, incurs relatively more computational expenses at a given iteration, but exhibits good convergence characteristics and provides multiple history matched models. The PSO method has emerged more effective compared to the NA and VFSA methods in the ICFM problem. It was also quite effective on the field application. On the other hand, the VFSA method requires comparatively more iterations to converge due to its sequential nature, but it has advantageous features when moderate computing resources are available.
Production and Rock Stability around a Frac-packed Gulf of Mexico Well
Authors: Han Gang , Revay Joe , Kalfayan Leonard , Perez Jorge , Walters Dale , Bachman Robert 
Published: October 2011

Abstract
Frac-packing has been widely used as an efficient sand control method in Gulf of Mexico fields. For frac-packed wells, rock stability issues within the reservoir are not normally considered when well drawdown levels are established. Instead the emphasis is on how the completion's integrity can be maintained given that mobile sand is produced. A frac pack can prevent sand from entering the wellbore; however, a skin increase and PI degradation occurring during production is not unusual. Conventionally, PI decline is believed to result from flow-related fines migration or from mechanical failure of completion equipment.
This paper presents a case in which theoretical quantification of sand failure around a frac pack provides a viable explanation of field observations. In addition to the skin at the fracture face, PI analysis indicates that additional damage, which contributes to gradually increasing PI degradation, has developed around the fracture. Extensive laboratory core testing has shown that fines are produced only moderately even at high fluid flow rates. However, significant permeability reduction occurs when loading stress increases to a threshold level. A near-wellbore geomechanical model with an embedded fracture has been coupled with a flow model to simulate drawdown and depletion effects on rock stability around the fracture.
The placement of a hydraulic fracture during frac-pack operations has been found to have two major effects upon the surrounding reservoir rock. Rock strength is increased at most locations around the fracture, a finding consistent with current industry perceptions. Secondly, certain regions in the vicinity of the fracture tip are weakened as stresses are elevated. Rock starts to fail at a certain level of depletion in either shear or compaction modes, depending upon the rock's location relative to the fracture and its strength and stress path. These findings demonstrate that rock stability needs to be considered when determining drawdown limitations in sand control completions, in order to avoid unexpected PI degradation.