bluuebunny/crossref_metadata_2025_split huggingface dataset:
Enhanced Directional Control with Bending Moment and Bending Tool Face Measurements
Authors: Pantin A. K. , Linke C. 
Published: June 2016

Abstract
This paper serves to further develop the method of using bending moment and bending tool face measurements to enhance directional control. The use of these bending measurements to actively steer the drillstring without directional survey information had never before been done in Trinidad, and this paper serves to capture the learnings from this case study. The background and theory of bending moment and bending tool face measurements have already been shown in previous SPE papers as well as their usefulness in providing steering information during casing exits.
The well plan in the case study required a sidetrack off of a cement plug, with the drillstring departing from the original wellbore at 90° right of highside, after which it followed a 3D wellpath before building to horizontal in the target sands. Due to the proximity of the sidetracked wellbore to the original wellbore, directional surveys using MWD tools were not possible for over 350 feet; during this stretch of ‘blind' drilling, the bending measurements were used to estimate survey data. The paper will describe the method in which these estimated surveys were calculated as well as the technique used to verify the bending measurements while running in hole prior to the start of drilling.
A gyroscopic multi-shot tool used to survey the ‘blind' drilling interval confirmed that the bending measurements provided good estimates when compared with the actual survey information. The use of the drilling dynamics tool to facilitate the ‘blind' drilling eliminated several gyroscopic runs, saving time and money for the client.
Improved Oil Recovery for the Complex Fault-Block and Multilayered Reservoir With Edge Water
Authors: Cui R. , Feng Q. , Li Z. , Guo F. , Yan A. , Liu S. , Tao Y. , Chen X. 
Published: June 2016

Abstract
The complex fault-block and multilayered reservoir with edge water, also known as the toothbrush-shaped reservoir, features in multiple oil layers, long narrow oil-bearing belts and the sufficient natural energy. Jin-94 block of Checheng oilfield is a typical toothbrush-shaped reservoir, where upward layer-by-layer production method has been implemented for dozen years. Nowadays, given that 78.2% of water cut and few oil layers that remain undeveloped, the sustainable production for a long term can’t be achieved anymore. However, only 14.2% of the original oil in place (OOIP) has been produced, indicating tremendous potential for the improvement of oil recovery.
The development method plays a dominative and decisive role in recovery efficiency. In order to comprehensively understand the characteristics of the development method, we studied the performance of two alternative methods on the basis of the current development technique in Jin-94. Numerical simulation is applied to production dynamic and comparative analysis of every method. Our simulations show that the optimizing methods exert better effects on oil production, which may serve as an efficient approach to the primary development of other similar fault-block.
To further improve the development performance, the distribution of residual oil in Jin-94 block is also analyzed via numerical simulation. Keeping the current development method of Jin-94 block unchanged, we coupled reservoir simulation with an optimization algorithm to study the capabilities of improved oil recovery (IOR) techniques for this block, i.e., reproduction of obsolete wells, feasibility of water injection, location of new oil wells and optimization of produced fluid intension. Simulation demonstrates that the degree of reserve recovery after optimization increases by over 5%.
This work will not only provide important and specific guidance for the improved oil recovery of the toothbrush-shaped reservoir, but also can improve economic benefits of the oilfield to cope with the challenges of low oil prices.
Real Time Slickline - Applications of New Technology in a Mature Field
Authors: Rivas C. , Bunraj C. D. , Medina A. I. , Araujo J. M. , Padilla A. , Gonzalez G. 
Published: June 2016

Abstract
The Teak, Samaan and Poui fields have been producing oil and gas for over three decades. Over 95% of the wells use gas lift with the remainder producing naturally. In order to address declining production the company conducts yearly rigless interventions to conduct work to remove organic and inorganic scale deposition, gas lift valve malfunctioning and the perforation of unproduced intervals. Throughout its tenure the company has had to take advantage of new and emerging technologies in order to optimize well intervention strategies.
Real time slickline was introduced into the rigless intervention on a trial basis. It was the intent to conduct a technical and cost benefit analysis on the services when used in the offshore operations. This scope of this paper is to present the findings of the trial and to review selected case studies where it has added benefit to the operations.
The real time slickline has been used in the TSP field primarily to conduct production logs (CCL, Pressure and Temperature surveys, Gamma Ray etc.) replacing the traditional memory gauges and convencional slickline unit. This solution has so far allowed the operation to make prompt decisions on well stimulation, gas lift valve change outs and pressure build up surveys while reducing overall logistics cost and intervention time. However, as will be shown, balancing reduced intervention times with the increased cost of the real time slickline versus traditional slickline must be managed in order to gain the full benefit of technology.
New Insights on Relative Permeability and Initial Water Saturation Effects During Low-Salinity Waterflooding for Sandstone Reservoirs
Authors: Shehata A. M. , Kumar H. T. , Nasr-El-Din H. A. 
Published: June 2016

Abstract
Low-salinity waterflooding (LSW) is an enhanced technique that improves oil recovery by lowering and optimizing the salinity of injected water. Previous research demonstrated that the initial water saturation and oil aging during LSW affect oil recovery. This work aims to validate and quantify these effects.
This laboratory study investigated the effect of injected brine, initial water saturation, and crude oil aging on relative permeability and low-salinity waterflooding performance in sandstone reservoirs. A set of comprehensive coreflood tests have been conducted using 3″ Bandera sandstone cores to examine the effect of initial water saturation and injection brine on the relative permeability curves. Additionally, six coreflood experiments were conducted to examine the effect of the connate water salinity variation on the relative permeability end points.
Four spontaneous imbibition experiments were performed using 6 in. length Buff Berea sandstone samples to investigate the effect of initial water saturation and aging on the performance outcome of low-salinity waterflooding. Two spontaneous imbibitions were performed using 20 in. length core samples. The objective of these two experiments was to study the effect of initial water saturation distribution across the core on the oil production using X-ray computed tomography.
Results obtained from coreflood and spontaneous imbibition tests suggest injected brine and initial water saturation have predominant influence on the oil recovery performance. As the initial water saturation increased from 23 to 41%, the oil recovery increased from 43.8 to 48.4% of OOIP using low-salinity waterflooding. Comparison between the high-salinity relative permeability and low-salinity water relative permeability showed that the end-point water relative permeability slightly decreased for the cores after using low-salinity brine as injected brine compared to the end-point water relative permeability after flooding with high-salinity brine for Bandera sandstone. The end-point relative permeability to water increased from 0.07 to 0.39 when the reservoir connate water salinity increased from 4,633 to 174,156 ppm for injected brine salinity of 500 and 5,000 ppm, respectively for Buff Berea sandstone. The un-aged core plugs with higher initial water saturation provided oil recovery higher than that with lower initial water saturation by 5% of OOIP for the low-salinity waterflooding.
Effectiveness of Low-Salinity and CO2 Flooding Hybrid Approaches in Low-Permeability Sandstone Reservoirs
Authors: Kumar H. T. , Shehata A. M. , Nasr-El-Din H. A. 
Published: June 2016

Abstract
Low-salinity waterflooding has been an emerging EOR/IOR technique in the recent times. LSW-alternating-CO2 injection has been particularly strong in yielding higher oil recoveries in some cases. Limited simulation studies haven been performed to properly exhibit the interpretation of experimental studies in this area.
Low permeability sandstones of significant clay content, and heavy west Texas crude oil with 29 °API were targetted for evaluating the potentials of LSWF and CO2 flooding. Coreflood experiments were conducted and interpreted by reservoir simulation, which enabled a better understanding of the underlying science of the studied IOR and EOR techniques. Five secondary waterflooding experiments and two LSW, CO2 hybrid processes were performed using aged 3 in. outcrop grey bandera sandstone cores. The wettability of the rock was tested using axisymmetric contact angle measurements to study the effect of injected brine salinity. The interfacial tension values were measured for the different brines and heavy crude oil systems. The corefloods were interpreted using reservoir simulation, by history matching the experimental oil RF and the pressure drop across the core. A detailed focus was laid on interpretation of SCAL relative permeability curves for the various waterflooding operations, by comparing curves generated from published correlations, history matched curves by simulation and that by Corey's correlations.
Fines migration and viscosity override of low salinity waters over heavy oil were highly influential on the oil recovery profile during low salinity waterflooding. Wettability alteration proved as effective during low salinity waterflooding, for longer injection and production periods. Corey's exponents were found to be premature indications of rock wettability during LSWF, proving importance and reliability of experimental wettability characterization. Low-salinity wateflooding proved to be marginally effective than conventional waterflooding for sandstones with high clay contents and low permeabilities. Low permeability sandstone reservoirs proved as great targets for Hybrid EOR techniques utilizing CO2 and LSW.
Characterization of In-Situ Bio-Surfactant in Microbial Enhanced Oil Recovery
Authors: Hosseininoosheri P. , Lashgari H. , Sepehrnoori K. 
Published: June 2016

Abstract
Capillary force limits the efficiency of water flooding by trapping the oil in porous media. High capillarity is caused by high interfacial tension (IFT) between oil and water that leads to a high residual oil saturation. Surfactants are widely used to reduce IFT and significantly mobilize the entrapped oil. However, the surfactants that are injected into a reservoir to lower the IFT several orders of magnitude may not be cost effective. A cost effective alternative for surfactant flooding is microbial enhanced oil recovery (MEOR). In the MEOR process, nutrients and natural bacteria are injected into a reservoir and both indigenous and injected microorganisms are able to react and then generate biosurfactants based on in-situ reactions.
Modeling a microbial enhanced oil recovery process requires coupling kinetics transport with local equilibrium transport in the presence of the surfactant phase behavior model (i.e. Hand's rule). In general, reservoir simulators do not model relative chemical reactions that consider the effect of essential environmental parameters such as temperature, salinity, and pH.
The main objective of this work is to present first order Monod kinetic equations as a function of temperature, salinity, and pH, which control the biodegradation reactions and microbial growth rate. This involves investigating the impact of biosurfactant adsorption, maximum growth rate, and nutrient concentration. Next, the effects of environmental factors are implemented in a four-phase chemical flooding reservoir simulator (UTCHEM). Finally, the simulator is used to history match coreflood experimental data to model the contribution of the cited parameters on oil recovery.
Results show that in-situ biosurfactant generation rates can be thoroughly modeled based on environmental factors and IFT can be reduced in a similar manner as surfactants. Simulation results show 10-15% incremental oil recovery using in-situ biosurfactant compared to waterflooding. The simulation results show that nutrient concentration, salinity and temperature are the most significant parameters influencing oil recovery, whereas pH has an insignificant effect.
The key findings of this work are the following: In-situ biosurfactant generation in a MEOR process is mathematically described.A new environmental model is implemented into the simulator.Various parameters influencing the efficiency of the MEOR process are investigated.
A Review of Water Reduction Techniques for Open Hole Gravel Pack Completions
Authors: Codrington Kofi , Nancoo-Ali Dana , Leung Daniel , Calvert Patrick , Nouwens Niels , Harris Dayn 
Published: June 2016

Abstract
Water reduction techniques were applied in the openhole gravel pack (OHGP) completions of four wells in Field C. Field C is operated by BP Trinidad and Tobago LLC (bpTT) and is located offshore Trinidad in the Columbus Basin. During the first phase of field development, six wells encountered economically recoverable reserves and first gas was achieved in 2007. The field produced at peak rates from December 2009 to April 2011. Between October 2010 and March 2013, four wells became liquid loaded due to aquifer influx, and production declined by ~ 80%.
The second phase of field development was scheduled to commence in 2016, and hence the bpTT field team began to investigate ways to revive the four liquid loaded wells and return them to production. Using experiences from BP Global Operations, and based on the assumption that the reservoir drive mechanism was bottom and/or edge water drive, the team decided to install zonal isolation devices. Also known as water shut off plugs; these devices are usually used in oil well casing applications and had never before been tested in gas well openhole gravel packs in Trinidad and Tobago. Each plug was set within an interbedded shale in the reservoir and screen joint of the completion to provide a vertical flow barrier. Due to uncertainty on the lateral extent of the shale and its ability to act as a barrier to water encroachment, an additional step of dynamic wellbore modelling was implemented. This was used to modify well bean up in order to minimize drawdown while maintaining the critical rate.
The well intervention campaign to install the plugs began in December 2013 and was executed using both slickline and e-line tools. One of the key considerations during job execution was depth control, to prevent setting the plugs too high in the wellbore and isolating gas bearing sands. This was achieved by correlating the gamma ray (GR) and Casing Collar Locator (CCL) logs with the original openhole logs. The plugs were installed by July 2014 and 75% of the wells were successfully offloaded with an average reduced WGR of 40%. This prolonged the producing life of the wells and improved the recovery factor by an average of 2%.
An Integrated Method to Characterize Shale Gas Reservoir Performance
Authors: Zhan J. , Seetahal S. , Cao J. , Hejazi H. , Alexander D. , He R. , Zhang K. , Chen Z. 
Published: June 2016

Abstract
The application of horizontal well drilling coupled with the multistage fracturing technology enables commercial development of shale gas formations. However, due to the complexity of fracture network propagation, simulation of such reservoirs is challenging and associated with uncertainties. In order to minimize the uncertainty of modeling, we correlate first-hand pumping schedule data with the reservoir performance directly through coupling a fracking process with a reservoir simulator. This provides us an integrated way to characterize a well trajectory, hydraulic fracture configurations and shale gas reservoir performance. In addition, a geomechanical effect on the reservoir performance under certain fracture configurations is studied using a geomechanics module developed by CMG Ltd.
GOHFER is widely used in a hydraulic fracking analysis. In this work, we couple GOHFER simulation output with the CMG module to determine the hydraulic fracture configuration. Thus, a method to correlate the first-hand pumping data (a slurry rate, slurry concentration and pumping pressure) with the reservoir simulator is given. Because of the stress sensitivity of a shale formation, we employ a linear-elastic constitutive law to depict the rock behavior with Young's modulus of 5,000,000 psi and Poisson's ratio of 0.2. Moreover, a Barton-Bandis model is used to describe the tensile opening of natural fractures for the dual-permeability reservoir model.
From a series of numerical simulation studies, we find that the effective normal stress will increase with the development of a shale gas reservoir which will lead to a decrease in porosity and permeability. For the base case without a geomechanics effect, it will produce higher cumulative gas production than the case with the geomechanics effect. When producing for six months, the difference of the cumulative gas production between the two cases is 14.3%. The integrated process provides insights about shale gas reservoir performance with available data and handy tools.
Characterization of Hydraulically-Induced Fracture Initial Water Saturation Distribution Using Arp's Correlation
Authors: Zhan J. , Seetahal S. , Alexander D. , Hejazi H. , Paul Cao J. , He R. , Zhang K. , Chen Z. 
Published: June 2016

Abstract
The application of coupled horizontal wells and the multistage fracturing technology to shale formations makes it viable to develop such hydrocarbon resources. In this paper, we focus on the water saturation distribution within hydraulic fractures and the uncertainty of water saturation distribution of the matrix around the hydraulic fractures resulted from fluid injection during a fracking process.
Arp's decline curve is introduced to depict initial water saturation distribution within the hydraulic fractures. Through modifying the decline index, it is easy to obtain a range of initial water saturation decline patterns which will lead to different water production profiles. Typical decline patterns such as linear, exponential, harmonic, and hyperbolic declines are used. As for the initial water saturation distribution of the matrix around the hydraulic fractures, the Stimulated Reservoir Volume (SRV) concept is implemented to identify the matrix region.
Through reservoir simulations, we find that the initial water saturation within the hydraulic fractures mainly contributes to the early water production. Various saturation distribution models result in about 25% differences in the total water production. On the other hand, a leak-off effect, which increases the initial water saturation of the matrix around the hydraulic fractures, contributes to the long term water production. This study provides insights about the uncertainty of water production during the development of shale gas reservoirs and guidelines for the history matching of water production rates.
Unearthing the Impact of the Geology of Aquifer Systems and Its Effect on Hydrocarbon Recovery in Gas Reservoirs in the Columbus Basin
Authors: Roopa Iannie , Rastogi Vandena , Dickey Doug , Baksh Kirk 
Published: June 2016

Abstract
Aquifer strength has a significant impact on recovery largely due to subsurface uncertainty in the aquifer connectivity and aquifer size. A wide range in recovery has been documented in the literature and has been similarly observed in gas reservoirs in the Columbus Basin (Trinidad) by comparing reservoirs with similar initial and platform pressures. Consequently, understanding aquifer systems can influence development strategies and economics. An example of this is in facilities design where stronger aquifers should have pipelines sized for large volumes of water post water breakthrough while the more volumetric fields should cater for lower pressures via compressors or eductors.
Uncertainties in aquifer support and gas-in-place estimates often introduce uncertainty in production forecasts. Dynamic data for some gas reservoirs reveal that aquifer pressure support strength varies between gas fields and also for individual reservoirs within some fields. This dynamic data includes the integration of surveillance data such as pressure transient derivative and saturation log time lapse data with material balance calculations. Typically the understanding of the geology of aquifers is limited to aquifer size, permeability, edge versus bottom water drive and high permeability streaks.
This paper collates a new combined dynamic and static analysis on a number of BP Trinidad and Tobago LLC mature reservoirs in the Columbus Basin that have been categorized from volumetric to strong aquifer behavior. This integrated view improves the overall understanding of how geology contributes to aquifer impact and helps to create integrated subsurface scenarios that characterize each aquifer system and enable better predictive capability in future developments.