bluuebunny/crossref_metadata_2025_split huggingface dataset:
Seismic Reservoir Monitoring of a Thermal EOR Redevelopment; Thick Heavy oil Field in Oman
Authors: Al Adawi Rashid , Rocco Guillermo , Al Busaidi Said , Al Maamari Abdullah , Al Ghafri Salah , Kiyashchenko Denis , Lopez Jorge , Berlang Wilfred , Zwaan Marcel 
Published: June 2014

Abstract
Petroleum Development Oman (PDO) is currently redeveloping a thick deep heavy oil reservoir using steam flooding. Steam has been injected in the first inverted 7-spot pattern (1P) since late 2008. An areal surveillance plan was created together with Shell International EP (SIEP) to test different monitoring techniques in order to select the most cost-efficient one for full field deployment. Ideally, the selected method would improve understanding of the thermal recovery concept and optimise further pattern development. The plan included three crosswell seismic profiles, 3DVSP and surface seismic, all in time-lapse mode. The 2006 surface seismic was used as the baseline for the surface seismic acquired in 2012. The data shows very good repeatability. However as the project construction phase took place after 2006, the 4D surface seismic was influenced by the 4D noise caused by surface changes. Detecting 4D signals is challenging particularly with the relatively small amount of injected steam. In contrast, crosswell seismic data and the 3DVSP were acquired after the construction work took place. The crosswell seismic 4D velocity profiles showed changes below and above top of reservoir, which led to the consideration of geomechanical effects. The 3DVSP data indicated reservoir changes towards the north of the injector which is in line with the temperature surveys, also indicating preferential changes towards the north. These encouraging results led to a second monitor 3DVSP acquisition followed by a pilot 3DVSP using a fibre-optic cable installed in the well for distributed acoustic sensing (DAS). The second monitor 3DVSP shows that previous 4D signals have moved further towards the north. It also indicates additional changes at the bottom perforation zone (as injection was shifted to bottom) with a preferential movement towards the north as well. Furthermore DAS VSP was found comparable enough with the conventional VSP and therefore it can detect reservoir changes. A plan is being worked to fit the existing observation wells with DAS cables and acquire a major 3DVSP baseline. The DAS cable will be combined with distributed temperature sensing (DTS) to maximize the value of the installation plan.
Evaluation of Well Performance for the Slot-Drill Completion in Low- and Ultralow-Permeability Oil and Gas Reservoirs
Authors: Odunowo T.O.. O. , Moridis G.J.. J. , Blasingame T.A.. A. , Olorode O.M.. M. , Freeman C.M.. M. 
Published: June 2014

Summary
Low- to ultralow-permeability formations require “special” treatments/stimulation to make them produce economical quantities of hydrocarbon, and at the moment, multistage hydraulic fracturing (MSHF) is the most commonly used stimulation method for enhancing the exploitation of these reservoirs. Recently, the slot-drill (SD) completion technique was proposed as an alternative treatment method in such formations (Carter 2009).
This paper documents the results of a comprehensive numerical-simulation study conducted to evaluate the production performance of the SD technique and compare its performance to that of the standard MSHF approach. We investigated three low-permeability formations of interest—namely, a shale-gas formation, a tight-gas formation, and a tight/shale-oil formation. The simulation domains were discretized with Voronoi-gridding schemes to create representative meshes of the different reservoir and completion systems modeled in this study.
The results from this study indicated that the SD method does not, in general, appear to be competitive in terms of reservoir performance and recovery compared with the more traditional MSHF method. Our findings indicate that the larger surface area to flow that results from the application of MSHF is much more significant than the higher conductivity achieved by use of the SD technique. However, there may exist cases, for example, a lack of adequate water volumes for hydraulic fracturing, or very high irreducible water saturation that leads to adverse relative permeability conditions and production performance, in which the low-cost SD method may make production feasible from an otherwise challenging (if not inaccessible) resource.
Optic Imaging of Two-Phase-Flow Behavior in 1D Nanoscale Channels
Authors: Wu Qihua , Bai Baojun , Ma Yinfa , Ok Jeong Tae , Neeves Keith B. , Yin Xiaolong 
Published: June 2014

Summary
Gas in tight sand and shale exists in underground reservoirs with microdarcy (µd) or even nanodarcy (nd) permeability ranges; these reservoirs are characterized by small pore throats and crack-like interconnections between pores. The size of the pore throats in shale may differ from the size of the saturating-fluid molecules by only slightly more than one order of magnitude. The physics of fluid flow in these rocks, with measured permeability in the nanodarcy range, is poorly understood. Knowing the fluid-flow behavior in the nanorange channels is of major importance for stimulation design, gas-production optimization, and calculations of the relative permeability of gas in tight shale-gas systems. In this work, a laboratory-on-chip approach for direct visualization of the fluid-flow behavior in nanochannels was developed with an advanced epi-fluorescence microscopy method combined with a nanofluidic chip. Displacements of two-phase flow in 100-nm-depth slit-like channels were reported. Specifically, the two-phase gas-slip effect was investigated. Under experimental conditions, the gas-slippage factor increased as the water saturation increased. The two-phase flow mechanism in 1D nanoscale slit-like channels was proposed and proved by the flow-pattern images. The results are crucial for permeability measurement and understanding fluid-flow behavior for unconventional shale-gas systems with nanoscale pores.
Combining Geostatistics With Bayesian Updating To Continually Optimize Drilling Strategy in Shale-Gas Plays
Authors: Willigers B.J.A.. J.A. , Begg S.. , Bratvold R.B.. B. 
Published: June 2014

SummaryWe present a new methodology to evaluate subsurface uncertainty during the development of shale-gas plays. Even after many wells are drilled, the average well production and the variation of well performance (economics) remain highly uncertain. The ability to delineate a shale play with the fewest wells and to focus drilling in the most-productive areas is a major factor in commercial success.The importance of probabilistic modeling in managing uncertainty in shale-gas plays is emphasized in several studies. The objective of this study is to develop a practical methodology that addresses these complexities and is dynamic, in the sense that the optimal drilling strategy can be continually updated as we learn the outcome of each well drilled.Maximizing the returns from a shale-gas play is essentially a problem of choosing well locations and number of wells to optimize production volumes and rates. Drilling policies must take account of many already-drilled locations, possible new drilling locations, spatial dependencies between performance at those different (possible) well locations, and the extent of uncertainty concerning whether a well will be economical. These factors cause typical valuation methodologies to be impractical because of the "curse of dimensionality."In this study, an unconventional play is divided into numerous segments. These segments are referred to as cells. In each cell, a fixed number of wells can be drilled. The chance of success (CoS) [of a well with a net present value (NPV) greater than zero] in any given cell is itself considered to be an uncertain variable. An initial probability distribution for the CoS of each cell is derived from analogous plays plus any available information about the specific play.The methodology proceeds as follows. First, as each new well (or group of new wells) is drilled, the outcome is used in combination with the prior probability distribution (with Bayes theorem) to create an updated probability distribution for the CoS of the relevant grid cell. Thus, our initial estimate can be continuously updated as more actual outcomes are realized. Second, the influence of the new CoS on the surrounding cells, because of spatial correlation, is updated by use of indicator Kriging (IK), a geostatistical technique. This combination of Bayesian update (BU) and IK is referred to as the BU-IK method.The methodology proposed in this study informs the development of drilling policies for shale-gas opportunities with a probabilistic model that accounts for the uncertainty in the CoS and its spatial dependency. The use of cells to represent a set of wells simplifies the analysis and greatly reduces the computing requirements. The methodology is applied to a well set from the Barnett shale in Texas.
Using Real-Time High-Resolution LWD Images to Navigate and Optimize Multi-Stage Completions in a Carbonate Reservoir
Authors: Janwadkar Sandeep , Murrell Paul , Thomas Mark 
Published: June 2014

Abstract
The Permian Basin of West Texas in North America is one of the most mature and prolific oil fields in the United States, continually evolving in production potential via the use of horizontal well drilling. Although initial well productivity has increased with new drilling and completion technologies, forecasting the success of a single well is still difficult because results may be inconsistent within the same section or across the play. This paper reviews the factors affecting well productivity and focuses on optimized completions design to grasp a better understanding of the geology and fracture network. Determining and identifying the zone of interest within the carbonate interval and then navigating within it with conventional LWD technology is a major challenge.
To overcome these challenges, real-time high-resolution LWD images were proposed. Azimuthal gamma ray and multiple propagation resistivity measurements were used to determine bed dip, correlate position within the reservoir and indicate formation porosity variations. Advanced LWD imaging tools provide visual confirmation of steering up and down within the reservoir and identify structural information, porosity changes, rock type, faults and fracture types.
Electrical images were incorporated as a crucial part of the completion strategy. Non-productive stages were eliminated by identifying and avoiding brecciated and faulted zones during completion, and improved completion efficiency and cycle time resulted in operator savings.
In conclusion, LWD images are used to more efficiently drain the reservoir by providing necessary information to stay longer in the target zone and optimize completion. LWD images also help explain production variances between wells targeting the same interval. This paper highlights sub-seismic faults and brecciated intervals that were not resolved using traditional gamma resistivity. By characterizing structural changes through the lateral, completion techniques can be customized to the specific well and maximize recoverable hydrocarbons. The new method enabled the lateral interval to increase from 77% in the offset well to 100% in-zone. The combination of factors, including better wellbore permeability, resulted in an 8% increase in oil production and 68% increase in gas production compared to the offset well during the first five full months of production.
Optimizing the Integration of 4D Seismic Data in History Matching: Which Data Should We Compare?
Authors: Sagitov Ildar , Stephen Karl D. 
Published: June 2014

Abstract
History matching by integrating time-lapse seismic with production data can become a more complex process. The additional constraints make it harder to find good models and this is made more difficult due to the nonlinearities encountered when predicting seismic behavior. A key aspect of this is the choice of domain in which to compare seismic data such as time domain or domain of inverted petro-elastic properties. We extend previous work where we examined the misfit surface from various domains by adding quantitative measures of nonlinearity in function of seismic on model parameters and analysing uncertainties in parameter estimates.
In this study we apply history matching to the models on the Schiehallion field. We compare the attributes of acoustic impedance derived from coloured inversion products to predicted acoustic impedance from a petro-elastic model. We call this a cross-domain comparison. To perform an alternative same-domain comparison, seismic prediction is based on the 1D convolution method. We then derive predicted pseudo impedance attributes, equivalent to those observed, using ’coloured inversion’. Models obtained in history matching using these two schemes are then examined.
Our results show that the outcome of history matching to seismic data is affected by the underlying static model conditioned to baseline 3D seismic in different domains which makes comparison of domains more difficult. It was demonstrated that cross-domain comparison of predicted impedances to observed seismic data increases non-uniqueness of parameter estimates. On the other hand, comparison in the same domain requires more modeling steps which adds to the nonlinearity because of narrowing frequency band.
Accurate reconciliation of predicted and observed seismic and production data via history matching is necessary for maximising the forecast capability of a simulation model. This significantly improves decision making by reducing risks and uncertainties in a field development.
Combining Pressure Falloff and Buildup Testing Using Wireline Formation Tester in Coal Bed Methane Environment
Authors: Osman Magdy Samir , Harfoushian Jack H. , Zerpa Bolivar C. E. , Thwaites Nick 
Published: June 2014

Abstract
Growing interest in gas reservoirs in nonconventional environments includes coal bed methane, which constitutes a potential important source of hydrocarbon gas in the UK but has been traditionally eclipsed by the conventional offshore oil and gas production. The current coal bed methane projects exist in different parts of the UK mainland. Drilling of these targets requires the use of minimum overbalance and nondamaging fluids.
The evaluation of coal bed methane reservoirs has its technical challenges. One of the challenges is to estimate the coal permeability by using both injection and production tests to ascertain coal cleat behavior. Although normal testing techniques can be used, interval testing using wireline can be more efficiently deployed to test individual coal bed seams. Traditionally, either an injection test or production test was applied to coal bed seams. In this paper we present a new approach that combines injection and buildup testing.
The methodology deploys a straddle packer string with a downhole pump on wireline. The packer spacing can be adjusted prior to deployment to suit the expected height of the coal bed to be tested. The tool is capable of both injection into and producing from the coal bed interval with the minimum storage volume. Downhole packer interval pressure is monitored on surface. Both the injection pressure and the drawdown pressure must be limited to avoid putting excessive force on the coal seam while maintaining single-phase flow.
Data from a recent application of the technique is presented for two different tested intervals. Obtaining permeability data from both falloff and buildup helps insure consistency between the tool data sets although some difference in the response between the two techniques results from the nature of the coal bed seam at each particular interval.
History Matching of the Norne Full-Field Model With an Iterative Ensemble Smoother
Authors: Chen Yan , Oliver Dean S. 
Published: June 2014

Summary
Although ensemble-based data-assimilation methods such as the ensemble Kalman filter (EnKF) and the ensemble smoother have been extensively used for the history matching of synthetic models, the number of applications of ensemble-based methods for history matching of field cases is extremely limited. In most of the published field cases in which the ensemble-based methods were used, the number of wells and the types of data to be matched were relatively small. As a result, it may not be clear to practitioners how a real history-matching study would be accomplished with ensemble-based methods.
In this paper, we describe the application of the iterative ensemble smoother to the history matching of the Norne field, a North Sea field, with a moderately large number of wells, a variety of data types, and a relatively long production history. Particular attention is focused on the problems of the identification of important variables, the generation of an initial ensemble, the plausibility of results, and the efficiency of minimization. We also discuss the challenges encountered in the use of the ensemble-based method for complex-field case studies that are not typically encountered in synthetic cases.
The Norne field produces from an oil-and-gas reservoir discovered in 1991 offshore Norway. The full-field model consists of four main fault blocks that are in partial communication and many internal faults with uncertain connectivity in each fault block. There have been 22 producers and 9 injectors in the field. Water-alternating-gas injection is used as the depletion strategy. Production rates of oil, gas, and water of 22 producers from 1997 to 2006 and repeat-formation-tester (RFT) pressure from 14 different wells are available for model calibration. The full-field simulation model has 22 layers, each with a dimension of 46 × 112 cells. The total number of active cells is approximately 45,000.
The Levenberg-Marquardt form of the iterative ensemble smoother (LM-EnRML) is used for history matching. The model parameters that are updated include permeability, porosity, and net-to-gross (ntg) ratio at each gridblock; vertical transmissibility at each gridblock for six layers; transmissibility multipliers of 53 faults; endpoint water and gas relative permeability of four different reservoir zones; depth of water/oil contacts; and transmissibility multipliers between a few main fault blocks. The total number of model parameters is approximately 150,000. Distance-based localization is used to regularize the updates from LM-EnRML. LM-EnRML is able to achieve improved data match compared with the manually history-matched model after three iterations. Updates from LM-EnRML do not introduce artifacts in the property fields as in the manually history-matched model. The automated workflow is also much less labor-intensive than that for manual history matching.
Effects of Brine on Crude Oil Viscosity at Different Temperature and Brine Composition - Heavy Oil/Water Interaction
Authors: Gachuz-Muro Heron , Sohrabi Mehran 
Published: June 2014

Abstract
For decades, it has been observed that temperature has a significant impact on viscosity reduction, mainly, in heavy and extra-heavy oils where increasing the temperature will improve the flow of oil through the reservoir. Austad and his group have reported that three main ions (SO42−, Mg2+, Ca2+) are potential determining ions for improving oil recovery in carbonate rocks. Both of them must act together. Their studies focused on studying light oils. At the same time, they pointed out the importance of injected fluid/crude oil/rock interactions.
Water injection is the most widely used oil recovery technique which has been extensively applied globally in both light and heavy oil reservoirs for decades. Historically, the composition of injection water is dictated by the source of water available for injection. However, recent investigations have shown that the composition of the flood water can have a significant impact on oil recovery achived by water flood. Both total salinity and individual ions content of water have been shown to affect the performance of water flood. It has also been observed that interactions between water and crude oil may affect the oil viscosity. Most of the available research results are on light oil systems but the impact of water composition and its interactions with heavy oil have not been investigated.
In this paper, we have experimentally investigated the interactions between brine and heavy oil. The focus of the study was largely on the impact of brine on heavy crude oil viscosity. Four different heavy oil samples were selected from a group of reservoirs and tested in this study. Experiments were conducted using different types of water at different temperatures. Synthetic seawater, formation water, normal brine and distilled water were used as selected brines. The heavy oils were brought in contact with selected brines such that each sample (system) consisted of 80/20 (brine/heavy oil) volume percent. The viscosity and water contact of the each oil was measured before and after the oil had been in contact with brine.
The results of this paper indicate the crude oil viscosity may be altered due to contact with brine. The composition of brine as well as crude oil affect whether the oil viscosity increases, decreases or remains unchanged. The results are important for water injection and handling both on the surface and also in the reservoir.
The Effect of Well Orientation (Vertical vs. Horizontal) on CO2 Sequestration in a Water Saturated Formation-Saline Aquifer in Western Australia
Authors: Tsar Mitchel , Ghasemiziarhani Mohsen , Ofori Kofi 
Published: June 2014

Abstract
Unconventional saline aquifers have injectivity problems due to low to moderate permeability, thickness and porosity, of the potential injection zones. Therefore, optimum injectivity rates to allow for more cost-effective sequestration requires enhancement techniques such as hydraulic fracturing of the injection zones and /or horizontal injection wells. This study presents analysis of different CO2 saline reservoir trapping and investigates the effect of well orientation on the CO2 injection rates and cumulative storage. Reservoir simulation is used to study the effect of well orientation on injectivity, based on reservoir and core data from a water saturated formation/saline aquifer in Western Australia. The results highlight benefits of using horizontal well over vertical well in improving the efficiency with which the CO2 will fill the reservoir (E - Factor).