bluuebunny/crossref_metadata_2025_split huggingface dataset:
Reservoir Fluid Characterization and Application for Simulation Study
Authors: Singh Kameshwar , Mantatzis Konstantinos , Whitson Curtis H. , Benjemia Radhia 
Published: September 2011

Abstract
The paper presents a methodology to develop and apply an equation-of-state (EOS) multi-fluid model for a field in Tunisia. The EOS model was developed by matching measured PVT data for a near-critical oil sample. The fluid characterization was used to estimate contamination level in oil-based-mud contaminated MDT samples, calculate decontaminated sample composition, estimate zone composition based on clean-up test measured oil-gas ratio, estimate fluid composition of some layers where samples were not available, and study the effect of gas condensate blockage and capillary number on simulated well performance.
In this field, reservoir fluids range from lean gas condensate to rich gas condensate and volatile oil. Clean up tests were conducted for all four zones encountered in the well, and oil-gas ratios were measured. During the clean up test of one zone, a near critical oil sample was collected and standard PVT experiments were conducted. Oil based mud (OBM) contaminated MDT samples were collected from six of the nine non-communicating layers, with OBM contamination levels between 20–65 wt% STO.
An EOS model was developed after matching measured PVT data on the near-critical oil sample. The MDT samples were decontaminated using measured mud composition. The calculated decontaminated "clean" sample compositions were used in a reservoir simulation model to initialize the layer from which the MDT sample was taken.
The developed EOS model was also used to estimate the fluid composition of different zones and layers without fluid samples. The zone fluid compositions were calculated based on measured test OGR. The EOS model, zone fluid compositions, decontaminated MDT samples, and layer mobilities were used to estimate fluid composition of the layers without samples.
This paper provides a methodology that can be used in any other field.
Modelling the Interfering Effects of Gas Condensate and Geological Heterogeneities on Transient Pressure Response
Authors: Hamdi H. , Jamiolahmady M. , Corbett P. W. 
Published: September 2011

Abstract
Numerous publications have investigated the effect of gas condensate fluid on the transient pressure well-test (WT) response. However, to the best of authors’ knowledge, its combined effect with geology has not been studied. Our findings presented here demonstrate that geology can complicate the WT response and make it difficult for interpretation. In this study the impact of geological heterogeneities on the WT response of a commingled braided-fluvial gas/condensate reservoir has been investigated. Numerical well-test data were generated for a single-well model with a commercial compositional reservoir simulator. Several sensitivity simulations were performed to explore the effects of correlation length, vertical permeability, relative permeability, production rate and drawdown time, on the pseudo-pressure derivate curves. The WT weighting Kernel function and the calculated well-pressure sensitivity coefficients were implemented to demonstrate different trends of drawdown and build-up responses encountered in this study.
The results clarified that some geological heterogeneities and production parameters can alter pressure distribution and condensate saturation, and mask the native model WT signatures. In this exercise, it was demonstrated that ramp effect, a geologically complex phenomenon in high net:gross commingled reservoirs, is affected by the condensate formation. This interfering phenomenon is reflected on the derivative curves and is magnified in the presence of the shorter correlation lengths, the lower vertical communications and the higher production rates. We also examined the stepwise stripping of the reservoir heterogeneity, in order to show the impact of each facies on the build-up and drawdown transient pressure response.. The time dependent sensitivity coefficients were calculated to show that the drawdown test is very sensitive to effective permeability in near wellbore areas, where condensate is prone to build up with time. In the build-up, on the other hand, the condensate saturation is almost invariant with time and affects the early time region. This work leads toward better understanding of the influence of geology in gas/condensate well-test interpretation.
A New Modified Genetic Algorithm for Well Placement Optimization under Geological Uncertainties
Authors: Morales A. N. , Nasrabadi H. , Zhu D. 
Published: September 2011

Abstract
Determining optimum location of wells is a crucial step in field development. A realistic geological model is an important factor in finding an accurate optimum well location. Usually history matching is used to come up with a realistic geological model. However, there is no unique solution to the history matching problem. Often several geological models could match the history data. This introduces some risk associated with the results of well placement optimization algorithm.
In this work, we present a new modified genetic algorithm (GA) for well-placement optimization under geological uncertainty. The inputs of the algorithm are possible geological models, and the level of risk that the user can accept. In the algorithm, the classic GA is modified so that: 1) in evaluating the fitness value (cumulative production or net present value) of each individual (well location) all the possible geological models provided by users are evaluated, 2) upon convergence of the algorithm, the output is one optimum well location as the fittest individual taking into account all the provided geological models, and 3) this optimum well location is selected based on the input user-defined level of risk. Most current available algorithms in the literature do not allow the user to input the risk factor desired and individual weights for each realization. The risk-constrained algorithm will provide different optimum well locations depending on the level of risk the user wants to take. All these features make the new algorithm much more efficient and applied than current well-placement algorithms in the literature for handling geological uncertainty.
We present the application of the risk-constrained algorithm to a horizontal well-placement optimization in a gas condensate reservoir, Qatar’s North Field, with multiple possible permeability fields and with different user-defined risk factors.
Improved Normalization of Time-lapse Seismic Data using NRMS Repeatabity Data to Improve Automatic Production and Seismic History Matching in the Nelson Field
Authors: Kazemi Alireza , Stephen Karl D. , Shams Asghar 
Published: September 2011

Abstract
Seismic history matching requires an accurate representation of predicted and observed data so that they can be compared quantitatively for automated inversion. Often, observed seismic data is obtained as a relative measure of the reservoir state or its change. Unless these data are calibrated, we need to normalise them. In this study we use NRMS, a repeatability measure to filter the observed time-lapse data so that normalization is more effective.
We apply this approach to the Nelson field. We use three seismic surveys over nine years of production. We normalize the 4D signature based on deriving a least squares regression equation between the observed and synthetic data. Two regression equations are derived as part of the analysis. To obtain the first, the whole 4D signature map of the reservoir is used for each interval while in the second, 4D seismic data is used from the vicinity of wells with a good match to production data. NRMS data is used to remove more anomalous measurements. Net:gross and permeability are modified to improve the match.
The best results are obtained when the normalization is performed using NRMS filtered maps of the 4D signature. The history match to the first six years of data is reduced by 55 per cent. The misfit for the forecast of the following three years is reduced by 29 per cent. If only production data is used in history matching, the history and forecast misfit reductions are 45% and 20% respectively. In this case the seismic misfit increases by 5% while in the best case it dropped by 6%.
Updating the reservoir by history matching of 4D data gives us better understanding of changes to the reservoir and also reduces risk in forecasting leading to better decisions about reservoir maintenance and infill well targeting.
Molecular Diffusion and Dispersion Coefficient in a Propane-Bitumen System: Case of Vapour Extraction (VAPEX) Process
Authors: Etminan S. Reza , Haghighat Parnian , Maini Brij B. , Chen Zhangxin 
Published: September 2011

Abstract
The solvent based recovery methods have recently attracted considerable attention due to environmental and energy concerns associated with thermal recovery methods. However, knowledge about molecular diffusion and mechanical dispersion as two key parameters to characterize these processes is limited. To find out the contribution of convective dispersion in enhanced production rates in VAPEX, three experiment sets were conducted for a system of propane and Athabasca bitumen. In the first set, molecular diffusion coefficient of propane in Athabasca bitumen was determined through a constant-pressure technique. A numerical technique was developed which also accounts for significant swelling of bitumen due to propane dissolution. The Levenberg-Marquardt method was utilized to estimate the molecular diffusivity through an inverse approach. In the other experimental set, a physical sand pack model was used to run the VAPEX experiments in the same temperature and pressure. The obtained dead oil production rate values were introduced into VAPEX analytical model. It allowed us to back-calculate the value of dimensionless number Ns. Finally, a set of PVT measurements were conducted to determine the viscosity and density of diluted bitumen for different values of propane concentration. This enabled us to find the dispersion coefficient from the definition of Ns term.
Molecular diffusion and convective dispersion are two important parameters for characterization of processes like VAPEX, ES-SAGD and other hybrid thermal solvent scenarios. Accurate estimation of these parameters improves predictions of compositional reservoir simulators. Obtaining propane molecular diffusivity into the bitumen and comparing it with our VAPEX back-calculated dispersion coefficients, would allow us to evaluate contribution of the convective dispersion to recovery rate enhancement in VAPEX experiments.
Secure Low-Cost, High-Volume Data Transmission of Wellsite Data to Remote Surveillance Centers
Authors: Sann A. Clark 
Published: September 2011

Abstract
Remote surveillance centers and intelligent production systems need data that often originates from wellsites located in extremely remote locations. Economical solutions are now available that provide consolidation of data at the wellsite, highly secure encryption, data compression, and data communications from most locations.
Traditionally, off-the-shelf supervisory control and data acquisition (SCADA) systems, fast computers, routers, virtual private network (VPN) appliances, and very small aperture terminal equipment have been employed for these purposes. Until now, the expense and complexity of these solutions have limited their use to only the most critical wells.
A new system has been developed that provides a low-cost and simple data consolidation/data transmission solution. What used to require several computers and associated networking and security hardware can now be accomplished in one low-cost, single board or rack-mounted computer.
Data can be acquired from a variety of wellsite end devices, such as pressure and temperature transmitters, chemical automation controllers, tank monitoring systems, down-hole electronic gauges, electrical submersible pumps (ESPs), and intelligent well systems. Also, numerous fiber-based sensors, such as distributed temperature sensors, real-time casing monitoring systems, and fiber-based down-hole pressure and temperature gauges can provide data to this system. This solution is intended for use in unattended remote locations, operable from solar power, and will function in extreme environments.
Acquired data can be provided locally via Modbus protocol or OLE for Process Control (OPC). Data can also be economically encrypted, compressed, and transmitted off the wellsite to remote surveillance centers in near real time. Data communication is performed via low-cost data communication systems such as cellular or Inmarsat's new Broadband Global Area Network satellite system.
Real-time production data, diagnostic data, and log data can also be transmitted off the remote wellsite, either automatically or upon demand.
Additionally, the system supports remote administration. Some measurement devices can be remotely reconfigured and remotely controlled. Examples of this include rescaling, recalibration, rebooting, restarting, and time synchronization of the end devices or of the data collection application.
This paper describes the system, how it has been deployed, and the proven benefits of the system.
Applications and Laboratory Studies of a New Class of Silica Polymerization Inhibitors of Bio-renewable Origin
Authors: Reyes-Garcia E.. 
Published: September 2011

Abstract
Silica precipitation during a sandstone acidizing treatment or its subsequent deposition post-treatment can negate the effectiveness of said acid treatment. Moreover, the removal of tenacious silica scale from a wellbore can sometimes result in matrix damage as a result of injecting the dissolved silicon into the formation. While this problem is well-known, effective solutions continue to be sought to sustain mature, hydrothermal, and siliceous wells that suffer from fines migration. Geochemical reactions operative in siliceous formations can induce various processes, such as silica migration, diagenesis, or hard scale. Laboratory investigations focused on preventing the formation of silica have identified a new class of silica polymerization inhibitor (SPI). The SPI mechanism is disruption or retardation of the condensation and polymerization of silicic acid monomers and oligomers and the ultimate growth of amorphous silica. Aluminum, commonly present in clay and feldspar minerals, can interfere with the SPI, so its effect has been studied. Dissolved Al3+ in the fluid must be regulated with the use of chelating agents to prevent precipitation, along with the silicon-SPI complex, at pH levels of interest in acidizing operations, namely &lt;4. Most effective acidizing treatments employ HF formulations, with HCl or organic acids, to dissolve the silicate minerals or scale in the near-wellbore region; hence, these studies are directed toward this application.
The SPI described in this work is a naturally occurring material of low molecular weight (MW) that effectively maintains in solution total dissolved silicon concentrations of up to 3,000 mg/L (0.12 M) below 2 pH, where minimal precipitation has been observed. Minimization of silica precipitation with typical concentrations of 1,000 to 2,000 mg/L of SPI was attained at &lt;4 pH. At this and lower pH levels, nearly constant silicon concentrations of 2,400 mg/L were maintained. These findings are significant to maximizing resource recovery because they allow the operator to consider alternatives for treatment processes geared toward higher-temperature wells, fracture acidizing, and expansion of the pH range of treatment fluids.
Successful Applications of Pressure-Rate Deconvolution in the Cad-Nik Tight Gas Formations of BC Foothills, Canada
Authors: Jones Jack , Chen Andrew 
Published: September 2011

Abstract
The Cadomin-Nikanassin (Cad-Nik) sandstone formations in the lower Cretaceous reservoirs along the reverse thrust faulting belt of North Eastern British Columbia, Canada, have emerged in the recent years as a new tight gas play. The low porosity (3% ~ 6%) of the rock matrix controls gas storativity, while the presence of natural fractures in the form of clusters or swarms allows significant and sustainable flow rates for commercial productions. Newly drilled wells are commonly hydraulically fractured to establish or enhance wellbore connectivity to the natural fracture network.
Seismic mappings of these structural unconventional gas reservoirs provide the early assessments of resource sizes and initial gas-in-place (IGIP), which usually bear huge certainties due to the difficulty of determining reservoir structural closures and pay porosity cutoffs. Regional analogue wells are often used to guide development decisions. Meanwhile estimating connected reservoir volumes through conventional gas material balances (P/Z vs. cum production) and production data analysis (RTA) has not been without challenges. Fairly long pressure buildups, on the order of 100's of hours, are often performed without seeing any pressure stabilization. The applicability of pressure extrapolation to these tests has not been systematically investigated. Thus, reliable average reservoir pressure estimates require much longer well shut-in times in order to perform meaningful gas material balance. Since this is not practical, confidence in material balance results requires a second, independent method for establishing connected well volumes to be used in comparisons and cross-checking. One possible choice is rate-transeint analysis (RTA) but, in these fields, many times well head pressure data are also unavailable or unreliable.
This paper presents two field case studies, which demonstrate the successful application of the pressure-rate deconvolution approach combining a well's long, high quality production rate history with accurate downhole pressure data from relatively short buildup tests. This approach allows the reservoir engineer to (1) reconcile the performance based EUR estimates with the volumetric OGIPs, (2) establish, at least, minimum well drainage size and connected volume and (3) pick possible infill-drilling opportunities. A final benefit is that this often leads to a better understanding of well/reservoir parameters.
Productivity Impairment Due to Fines Migration: Steady State Production Regime
Authors: Bedrikovetsky P.. , Vaz A.. , Machado F.. , Zeinijahromi A.. , Borazjani S.. 
Published: September 2011

Abstract
Permeability decline during corefloods with high rates has been widely reported in the literature. It has often been explained by the lifting, migration and subsequent plugging of pores by fine particles, which has been observed in numerous core flood tests. The phenomena have been connected to well productivity impairment during fines production that also has been widely observed in oilfields. The present paper derives formula for skin factor based on the modified particle detachment model with maximum retention function. The fines migration induced skin is shown to increase with increase of rate and initial attached fines concentration.
Successful Application of a Distance-to-Boundary Technology Under Tough Drilling and Reservoir Conditions
Authors: Salim D.. , Samaroo R.. , Barbosa J.. , Silva C.. , Guedes A.. 
Published: September 2011

Abstract
Accurate placement of a horizontal well within a reservoir can be complicated and with uncertainties (McLennan, 2006). That was the case for the 8.5-in. horizontal well in the study being reported. Uncertainty in the structural geology existed due to distance from the closest well (~500 m) and also the vast number of faults identified on the seismic data.
With the well supposedly landed in the reservoir, the expectation on start drilling sand was not met upon drilling out the casing shoe. Approximately 180 m MD of shale was encountered before making a decision to use the well for appraising the upper seismic reflector. The section was subsequently abandoned for a sidetrack that aimed at producing the upper sand lobe.
From the original casing shoe of the landing point, to access the upper sand lobe with the shortest shale section possible, a strong build in inclination to &gt;90° would be required upon exiting the shoe. Once the wellbore entered the reservoir sand package through the base, a change in trajectory was immediately required to avoid exiting through the top of the thin sand. The sooner the well entered the sand, the greater the success of the well because drilling more than 410 m MD would intersect the drainage radius of another producing well; hence, creating undesired production interference.
A new model was developed and the well plan was executed. Based on the model, approximately 140 m MD of shale was expected before intersecting the base of the reservoir; however, in actuality, 167 m MD of shale was drilled prior to intersecting the reservoir entrance. Within 20 m MD inside of the reservoir, an indication of the top of the reservoir was observed on the distance-to-boundary inversion. As a result, the trajectory was adjusted accordingly to prevent exiting the reservoir that resulted in achieving 60% of reservoir sand.
This case study will highlight how the combination of real-time distance-to-boundary mapping technology and proactive steering decisions aided in eliminating a second consecutive sidetrack of the horizontal section.
Designing Completions after Predicting Wellbore Dynamic-Shock Loads During Perforating
Authors: Burman J.. , Schoener-Scott M.. , Le C.. , Suire D.. 
Published: September 2011

Abstract
Oilwell casing perforation has been used in the industry since 1932 and was pioneered by the Lane-Wells Company who introduced the bullet-gun perforating technique. Shortly after the introduction of the bullet gun, explosive jet perforators were introduced, which provided a different and more aggressive way to perforate casing.
With the increased demand for oil and gas over the past decades, operators have been forced to explore deeper, hotter reservoirs to find the most prolific reservoirs. These deepwater opportunities have required constant changes to equipment and services to increase their technical capabilities for performing in more critical environments. Perforating with higher-shot densities, propellants, and larger perforating guns has been ongoing to meet these new challenges.
A major problem with these increases, however, is the difficulty in predicting dynamic wellbore behaviors that cause tubulars to collapse and bend and packers to unset as perforating guns were detonated. Research to understand the pressure behavior during the perforation event, in addition to the solid loading that is imparted to the tubulars, packers, and other completion hardware in the perforating assembly, was needed to enable the industry to go forward with a high level of confidence that wells could be completed safely and cost effectively.
This paper discusses a shock-wave computer modeling program that evaluates the mechanical risk factors of well components to ensure that the health, safety, environment, and service quality needs in a design are addressed. A time-marching, finite-differences technique is applied as the numerical method for both fluids and solids. The software is installed on a personal computer and typically executes the models within several minutes to several hours, depending on the complexity of the job design.
The physics-based model has been validated (Schatz et al. 1999 and Schatz et al. 2004) with special high-speed recorders that sense pressure, temperature, and acceleration at a sampling frequency of 115,000 samples per second.
This paper provides data from offshore oil and gas wells in the Gulf of Mexico to demonstrate the success of the design.