bluuebunny/crossref_metadata_2025_split huggingface dataset:
History Matching of Frequent Seismic Surveys Using Seismic Onset Times at the Peace River Field, Canada
Authors: Hetz Gill , Kim Hyunmin , Datta-Gupta Akhil , King Michael J. , Przybysz-Jarnut Justyna K. , Lopez Jorge L. , Vasco Donald 
Published: October 2017

Abstract
We present a novel and efficient approach to integrate frequent time lapse (4D) seismic data into high resolution reservoir models based on seismic onset times, defined as the calendar time when the seismic attribute crosses a pre-specified threshold value at a given location. Our approach reduces multiple time- lapse seismic survey data into a single map of onset times, leading to substantial data reduction for history matching while capturing all relevant information regarding fluid flow in the reservoir. Hence, the proposed approach is particularly well suited when frequent seismic surveys are available using permanently embedded sensors.
Our history matching workflow consists of two stages: global and local. At the global stage of history matching, large-scale features such as regional permeabilities, pore volumes, temperature and fluid saturations are adjusted to match seismic and bottomhole pressure data using a Pareto-based multiobjective history matching workflow. Rather than an artificial subdivision of the domain, the history matching regions are naturally defined based on an eigen-decomposition of the grid Laplacian and a spectral clustering of the second eigenvector (fiedler vector). The global updating is followed by local history matching whereby cell permeabilities are adjusted to further refine the history match using semi- analytic, streamline-based model parameter sensitivities. The power and efficacy of our proposed approach is illustrated using synthetic and field applications.
The field example involves steam injection into a heavy oil reservoir at Pad 31 in the Peace River Field (Alberta, Canada) with daily time lapse seismic surveys recorded by a permanently buried seismic monitoring system (Lopez et al. 2015). In our specific application, we have used time lapse data (in terms of two-way travel time) from a Cyclic Steam Stimulation (CSS) cycle in the pad with a total of 175 seismic surveys. With a single onset time map derived from this data we were able to capture the propagation of pressure and saturation fronts and significantly improve the dynamic model through the estimation of permeability distribution, fluid saturation evolution and swept volume. With this methodology we correctly identified and further refined the location of stimulated zones as inferred before from reservoir engineering judgement and manual adjustments aiding better understanding of CSS behavior in the studied field. The results clearly demonstrate the effectiveness of the onset time approach for integrating large number of seismic surveys by compressing them into a single map. Also, the onset times appear to be relatively insensitive to the petro elastic model but sensitive to the steam/fluid propagation, making it a robust method for history matching of time lapse surveys.
Active Acoustic Ranging to Locate Two Nearby Wellbores in Deepwater Gulf of Mexico
Authors: Poedjono Benny , Alatrach Samer , Martin Albert , Goobie Roger B. , Allen William T. , Sweeney Eugene 
Published: October 2017

Abstract
Salt drilling in Deepwater Gulf of Mexico (GOM) presents unique challenges. One of these challenges is the effect salt has on ranging technologies used in contingency relief well designs. A new technique called Active Acoustic Ranging (AAR) addresses the challenge of locating and tracking the target wellbore to the interception phase. This case study details the degree of precision that this new technique provided while locating two nearby wellbores within salt. This study is intended to improve industry awareness and understanding of relief well ranging options available to the industry, specifically wellbore ranging activities conducted within a salt formation.
Sonic logging started in the early 1930s to determine rock characteristics by measuring the refracted signals from a combination of transmitters and receivers. The technique evolved by recording acoustic signals beyond the refracted zone, by positioning the transmitters and receivers downhole in the logging tool.
AAR utilizes surface seismic processing methods to determine azimuthal direction and distance of compressional and shear acoustic signals, reflected from around the borehole. After processing the reflected signals, the distance and direction of nearby wellbores can be determined. This can be effective in salt formations, where resistivity inhibits use of active electromagnetic ranging tools.
This case study presents test results conducted in a GOM Deepwater operation to locate two nearby wellbores, a cased hole and an open hole, using AAR. It shows that AAR signals can be successful in locating offset wellbores within salt formations. The acoustic signals, both compressional and shear, were recorded using a stack of 13 receivers. Each stack had 8 sector azimuthal receivers to determine the distance and direction of the corresponding target wellbores.
By utilizing compressional and shear signals generated from the various distances of monopole and dipole transmitters, a redundant process was provided to determine the location of the target wellbores with a high degree of accuracy.
In addition, the acoustic images provided estimates of the salt quality, which can be used to select the interception location for hydraulic kills. The maximum ranging distance is dependent on the velocity and attenuation of the transmitted acoustic signals in the traversed formations. Salt typically has higher velocities that will enable ranging at greater distances than other formations.
One of the primary benefits of this technique is the ability to provide two different measurements using monopole and dipole sources to locate nearby wellbores. This reduces uncertainties that may arise when ranging with a system using only a single measurement. AAR benefits from the salt formation, whereas other ranging technologies, i.e. electromagnetic, were not optimized for salt. AAR increases the ranging options in salt formations.
Developing Equations of State for Unconventional Source Rock Fluids
Authors: Allouache A. , Harrison R. , Turek E. 
Published: October 2017

Abstract
This paper outlines a methodology for constructing equation of state (EOS) descriptions and source rock fluid composition correlations to describe the fluid properties of entire unconventional plays, such as the Eagle Ford shale play and the Permian Basin's Delaware Basin Wolfcamp formation. This methodology is tailored to match the quality of the available data in each play.
Sufficient reservoir fluid samples (either recombined companion surface separator samples or downhole fluid samples) with full pressure-volume-temperature (PVT) laboratory studies are required to span the range of fluids found in each play. These data provide the basis for tuning EOS parameters for C7+ pseudo-components and binary interaction parameters.
Source rock fluid composition varies with thermal maturity of the reservoir. The most direct measure of thermal maturity is C7+ mole weight (MW) determined for fluid samples; however, in areas with unstable production, such as slugging or cycling wells, a three-month-average producing condensate/gas ratio (CGR) is utilized as the basis for correlating the composition. The resulting tuned EOS models and source rock fluid composition correlations provide fluid descriptions for forecasting models, well models, artificial lift design tools, and facility models. When combined with proprietary maps of source rock thermal maturity measures, the models discussed here can be utilized to estimate fluid properties for undrilled acreage.
Advanced Well Control using Rapid Cross-linking Polymers
Authors: Nedwed Tim , Kulkarni Kaustubh , Jain Rachna , Mitchell Doug , Meeks Bill , Allen Daryl P. , Edgecombe Brian , Christopher J. Cruce 
Published: October 2017

Abstract
Industry maintains well control through proper well design and appropriate controls and barriers. This has made loss of well control a very low probability event. Currently the final barrier to maintain control is a valve system (blowout preventer or BOP) located on top of wells capable of sealing around or shearing through obstructions that might be in the well (e.g. drilling pipe and casing) to isolate the well. Although the risk is low when proper drilling practices and design are employed, there are still concerns about well control especially for operations in sensitive environments. Adding an additional barrier could alleviate these concerns.
One scenario for well control loss is if the BOP fails to seal allowing drilling fluids and reservoir fluids to flow. We are currently evaluating a concept to respond to such an event and seal leaking BOPs by injecting a liquid monomer and a catalyst below a BOP leak point to form a polymer-plug seal.
Mixtures of dicyclopentadiene (DCPD) and other monomers mixed with a ruthenium-based catalyst cause a rapid polymerization reaction that forms a stable solid. These reactions can occur under extreme temperatures and pressures and withstand significant contamination from other fluids and solids.
Lab studies have shown that DCPD-based polymer plugs can withstand axial stress of 15,000 psi without significant deformation even at temperatures of 200°C and with 20% drilling fluid contamination. For well control, one option is to preposition monomer mixes and catalyst into pressurized cannisters located at or near subsea BOPs while drilling high-complexity wells. Connecting the pressurized cannisters to appropriate ports on the BOP will allow rapid transfer. During a well-control event, actuating valves would rapidly force the monomer mixes and catalyst from the cannisters into the BOP to initiate polymerization. Polymerization reactions can be as short as a few seconds depending on the monomer mix and catalyst. The resulting solid polymer plug will block the leak path to potentially seal the well.
This paper describes the concept details and summarizes the current status of research.
Intelligent Longest Stroke Reciprocating Pumping System for Production and Cost Optimization
Authors: Ghareeb Mohamed , Kennedy Dave , Woo Alvin 
Published: October 2017

Abstract
Worldwide, as conventional oil resources are depleted; reciprocating sucker rod pumping systems are becoming the most common type of artificial lift methods for onshore wells.
With the growing number of sucker rod pumped wells, the value of optimization and cost control is continuously increasing. Oil companies might have different views of the meaning of "Optimization" but the technology driver nowadays is to gather all possible data/ information to control well operation and system performance around the well in one smart well lift system. This smart system will use the gathered information to optimize the well by decreasing lifting costs, increasing production and optimizing the power consumption. This is additional to enhancing the safety by reducing the well site operations to change well running parameters for well optimization. All these will perform automatically without relying on manpower interference at the wellsite and it will not require stopping the well. This will reduce the manpower safety hazard and well downtime,
This paper will discuss the latest technology in sucker rod pumping system regarding the system capabilities as production, depth, optimization, remote monitoring and control. It will share several case histories from different area worldwide showing the benefits achieved by applying the ultra-long stroke length intelligent unit. These novel applications help operators in Producing high volume from deep wells.Reduced OPEX (operating expense) by Minimize Well Interventions, installation, changing units running parameters for well optimization (speed, stroke length and balancing)Reduce friction between rods and tubing (decrease side load) and extending well running life.
Analytical Method for Voidage Replacement Ratio Calculation in Reservoirs With Quasicritical Fluids
Authors: Rosario O. , Hernandez J. C. , Korabelnikov A. I. , Albornett L. 
Published: October 2017

Abstract
Injection Scheme Surveillance in secondary recovery processes is essential to guarantee their best performance. For energy maintenance processes such as Fluid Injection, the Voidage Replacement Ratio (VRR) represents a relevant surveillance factor, not only for fluid balance calculations (Injection vs. Production) but also for its relation to the reservoir energy decline rate.
According to some reservoir complexities (for example, compositional variation vs. depth), accurate calculations for this parameter may require a robust model such as a Numerical Reservoir Simulator and its corresponding working stages. However, by understanding the Essential Reservoir Mass Balance principles, these calculations can be completed with a simpler approach, in a representative manner.
Most VRR correlations consider a Black Oil reservoir fluid behavior. However, some reservoirs will produce considerable deviations in VRR calculations due to variations in thermodynamic properties in the reservoir column, such as compositional variations with depth or near-critical conditions.
In this technical paper, an analytical method is presented in order to determine the VRR for near-critical condition reservoirs and its corresponding results, against its equivalent model using numerical reservoir simulation calculations. This article suggests a workflow considering the existence of both Equation of State and PVT analysis for reservoir volume fluid calculations by the integration of PVT correlation adapted to the type of produced fluid.
The application of this methodology illustrates the advantages of having a tool for the Reservoir Management Surveillance. This approach provides representative VRR estimations in a practical manner, particularly useful for cases when the required resources for Numerical Reservoir Simulations are not available.
A Novel Approach to Rejuvenate Brown Field by Validating Dynamic Model Response with Near-Wellbore Saturation Monitoring
Authors: Mishra Shubham , Natarajan Karthik Kumar , Aggarwal Akshay , Ojha Aditya , Rincon Alexander , Khambra Isha , Kumar Ajit , Agrawal Gaurav , Kakoty Pankaj , Baruah Neelimoy , Dhiraj Sanjay Kumar 
Published: October 2017

Abstract
Oil India Limited's (OIL) operational areas, in Upper Assam-Arakan Basin, are located in a seismically active thrust fault zone (Bora et al., 2010). Multiple stacked layers, highly faulted anticlines and large number of compartments make the structural setting of these fields very complex. In terms of lithology, some of these reservoirs are low resistivity pays, leading to ambiguities in interpretation due to fresh water environment and complexities in evaluation of hydrocarbon-bearing and water-bearing sands (Koithara et al., 1973, Borah et al., 1998).
Greater Nahorkatiya and Greater Jorajan, since the inception of commercial production in the 1950s, have been intensively studied to find prospective sweet spots, perforation intervals for new well locations and potential workover candidates. These forecasts, guided only by dynamic numerical model results, have had mixed results when implemented in the field. A validation of the dynamic model forecasts with near-wellbore saturation logs, can help to reduce uncertainty. This paper describes the success stories in field implementation of workovers, guided by dynamic reservoir model results and cross-validated with Pulse Neutron Tool (Roscoe et al., 1991, Schnorr, 1996) log recordings.
The intricacy of delivering a precise dynamic reservoir model was managed by state-of-the-art seismic-to-simulation workflows, an integrated approach to improve the quality of the geological model and specific analytical techniques to fill in the data gaps. The calibrated model was analyzed for workover opportunities of zone transfer. In zones with high confidence, (i.e. high Hydrocarbon Pore Volume (HCPV), high porosity, permeability, etc., perforation intervals were recommended for hydrocarbon saturation monitoring to confirm the near-wellbore saturation predicted by the model. This workflow was followed in 8 wells which added immense value both technically and economically.
The validation of model predictions with near-wellbore saturation was carried out in old wells which helped in making informed decision about tapping bypassed hydrocarbon pockets. It helped to avoid non-hydrocarbon bearing zones, which were removed from the existing workover plan. Moreover, it introduced confidence in the dynamic model which will be used in future for more aggressive economic development of the fields. This approach resulted in better understanding of the reservoir characteristics which led to identification of some potential reserves which could be characterized as "Reserve Growth".
Degasification by Absorption-Based Gas Stripping
Authors: Crawford Steve , Korpiel John , Velastegui Oscar 
Published: October 2017

Abstract
A fouling-resistant gas stripping technology was tested for removing dissolved gas species from dirty water streams such as produced water. The CoStrip™ degasifier uses a countercurrent stream of microbubbles to absorb gas species from the water stream into a stripping gas. The microbubbles act as carriers, removing dissolved gases such as hydrogen sulfide (H2S), carbon dioxide (CO2), and BTEX (Benzene, Toluene, Ethylbenzene, and Xylene) compounds. The technology is able to treat water with a high level of suspended solids and oils, which would otherwise clog a conventional packed tower or sieve tray gas stripper. A pilot test was conducted on heavy oil (API-10 to 12) produced water in California, which demonstrated a variety of benefits. The benefits of a degasifier installed upfront of a produced water treatment train include: dissolved gas removal, safe use of open-top equipment downstream due to H2S reduction, lower downstream chemical consumption and sludge generation due to dissolved gas removal, corrosion mitigation, and improved downstream membrane longevity.
The Study of Gel Conformance Control Effect within Carbonates with Thief Zones by Advanced NMR Technique
Authors: Alshehri Amar J. , Wang Jinxun , Kwak Hyung T. , AlSofi Abdulkarim M. , Gao Jun 
Published: October 2017

Abstract
Carbonate's extreme heterogeneity in the form of fracture corridors and super-permeability thief zones challenges the efficient sweep of oil in both secondary and tertiary recovery operations. In such reservoirs, conformance control is crucial to ensure injected water and any EOR chemicals optimally contact the remaining oil with minimal throughput. Gel-based conformance control has been successfully applied on both sandstone and carbonate reservoirs. Achieving effective in-depth conformance control in high-temperature reservoirs, however, remains a challenge due to severe gel syneresis and significant reduction in gelation time. The first step to improve the performance of gel in these challenging environments is the accurate understanding of gel conformance control mechanism inside reservoir rocks.
In this work, a laboratory study was conducted to evaluate a polyacrylamide/chromium gel system for application in a high-temperature and high-salinity (HTHS) carbonate reservoir. Oil displacement experiments on carbonate core samples, combined with nuclear magnetic resonance (NMR) measurements were performed to demonstrate oil recovery improvement by gel treatment and illustrate the mechanisms of the improvement. In these tests, the gel solution was injected into specially prepared heterogeneous carbonate composite core samples, in which different configurations of high-permeability channels were created. Gel treatment was conducted after waterflooding and was followed by chase waterflooding. Oil recovery improvement by gel treatment was 18% of original oil in core (OOIC) in the composite core with high permeability channels extending mid-way through the composite while the improvement was 38% OOIC in the composite core with channels extending all the way through the composite. Detailed spatial fluid variations inside the core samples before and after gel treatment were closely monitored using advanced low-field NMR techniques. Heavy water (D2O) was used in place of water to enhance the contrast between oil and brine for NMR by eliminating the protons in the aqueous phase. NMR measurements indicated that the bypassed oil during waterflooding was effectively recovered after gel treatment.
Results in this study demonstrate the potential of the studied gel system and its favorable impact on sweep efficiency improvement application in HTHS carbonate reservoirs. The NMR study enhances our understanding of how gel helps improve sweep efficiency of subsequent floods through blocking/reducing the permeability of highly-conductive zones.
Interpretation of Interwell Chemical Tracer Tests in Layered Heterogeneous Reservoirs with Crossflow
Authors: Shen Tong , Moghanloo Rouzbeh Ghanbarnezhad , Tian Wei 
Published: October 2017

Abstract
This paper presents a systematic approach to evaluate limited crossflow between layers of a stratified reservoir using interwell chemical tracer test. Previous studies either entail no crossflow between layers or assumes an established vertical equilibrium across transverse direction (owing to viscous/capillary/gravity driving mechanisms); however, they fail to detect the presence of limited crossflow between layers through a ‘bridge’; ‘bridge’ in this study is defined as apathwaythrough which crossflow takes place with an adjacent layer. Obviously, crossflow may take place through several bridges along a layer.
A new formulation is developed to study and detect the limited crossflow. The crossflow is detected through monitoring of the fraction of total injected fluid that arrives at the producer from each layer as a function of time. We employed both numerical simulation and field examples to verify the proposed method. A transition period is identified during which thefraction of injected fluid flowing through each layer significantly changes because of crossflow. Our results indicate that tracer can be used to evaluate number of bridges. The distance between injector and the bridge location can significantly change the interwell tracer results. Identification of crossflow between layers and evaluation of transition zone significantly improves the current efforts to understand reservoir complexity and sweep efficiency. The outcome of this research can help design more successful EOR processes.
Impact of Relative Permeability Hysteresis on Water-Alternating-Gas WAG Injectivity: Modeling and Experimental Study
Authors: Chen Yuguang , Wu Stanley , Zhou Dengen , Chawathe Adwait , Inouye Art 
Published: October 2017

Abstract
Gas injection is a proven enhanced oil recovery (EOR) process, representing the leading EOR-technique in the United States. In recent years, gas EOR technologies are expanding to more challenging (deeper and tighter) reservoirs. In gas injection, there are two basic techniques – continuous gas flooding and water-alternating-gas (WAG) injection. The WAG injection promises improved sweep efficiency, with water being used for mobility control and stabilizing displacement fronts, but suffers from injectivity loss due in part to gas trapping. This injectivity loss can have a major impact on project economics. In this work, we study the modeling of relative permeability hysteresis and its impact on WAG injectivity under both immiscible and miscible conditions.Core flooding experiments are also performed and simulated to understand and quantify the WAG injectivity. Our study showed that the most significant impact of gas relative permeability hysteresis on WAG injectivity lies in the water injectivity reduction following gas flooding. Experimental results confirmed the reduced water injectivity, and this effect can be modeled and sufficiently captured by the gas relative permeability hysteresis.