bluuebunny/crossref_metadata_2025 huggingface dataset:
An Improved Inversion Workflow Jointly Assimilating 4D Seismic and Production Data
Authors: Jin Long , Gao Guohua , Vink Jeroen C. , Chen Chaohui , Weber Daniel , Alpak Faruk O. , Hoek Paul van , Pirmez Carlos
Published: June 2012

Quantitative integration of 4D seismic data with production data into reservoir models is a challenging task. One important issue is how to properly quantify the uncertainty, or the posterior probability distribution (PPD). The Very Fast Simulated Annealing (VFSA) is a stochastic searching method, whereas the Simultaneous Perturbation and Multivariate Interpolation (SPMI) is a model-based local searching method. The stochastic features of the VFSA provide the feasibility of identifying possible multiple peaks of a PPD, but it converges very slowly. On the other hand, the model-based SPMI method has the advantages of effectively utilizing the smooth features of an objective function, and thus can converge to local optimum very quickly. More importantly, the Hessian of the objective function, or the covariance matrix of the PPD, can be estimated by the SPMI method with satisfactory accuracy. However, it is very difficult to identify multiple optima by applying the SPMI method alone. In this paper, we propose an efficient joint inversion workflow by appropriately integrating the two derivative free optimization (DFO) methods. The complementary features of the two methods can further improve both applicability and efficiency of this joint inversion workflow. We tested the workflow with a 3D synthetic model and a real field case. Our results show that the integrated method is efficient and can deliver good results for jointly assimilating 4D seismic and production data.
Ekofisk 4D Seismic - Seismic History Matching Workflow
Authors: Tolstukhin Evgeny , Lyngnes Bjarne , Sudan Hari H.
Published: June 2012

This presentation outlines an integrated workflow that incorporates 4D seismic data into the Ekofisk field reservoir model history matching process. Successful application and associated benefits of the workflow benefits are also presented.

A seismic monitoring programme has been established at Ekofisk with 4D seismic surveys that were acquired over the field in 1989, 1999, 2003, 2006 and 2008. Ekofisk 4D seismic data is becoming a quantitative tool for describing the spatial distribution of reservoir properties and compaction. The seismic monitoring data is used to optimize the Ekofisk waterflood by providing water movement insights and subsequently improving infill well placement.

Reservoir depletion and water injection in Ekofisk lead to reservoir rock compaction and fluid substitution. These changes are revealed in space and time through 4D seismic differences. Inconsistencies between predicted 4D differences (calculated from reservoir model output) and actual 4D differences are therefore used to identify reservoir model shortcomings. This process is captured using the following workflow: (1) prepare and upscale a geologic model, (2) simulate fluid flow and associated rockphysics using a reservoir model, (3) generate a synthetic 4D seismic response from fluid and rock physics forecasts, and (4) update the reservoir model to better match actual production/injection data and/or the 4D seismic response.

The above-mentioned Seismic History Matching (SHM) workflow employs rock-physics modeling to quantitatively constrain the reservoir model and develop a simulated 4D seismic response. Parameterization techniques are then used to constrain and update the reservoir model. This workflow updates geological parameters in an optimization loop through minimization of a misfit function. It is an automated closed loop system, and optimization is performed using an in-house computer-assisted history matching tool using evolutionary algorithm.

In summary, the Ekofisk 4D SHM workflow is a multi-disciplinary process that requires collaboration between geological, geomechanical, geophysical and reservoir engineering disciplines to optimize well placement and reservoir management.
Adjoint-based History-Matching of Production and Time-lapse Seismic Data
Authors: Van Essen G. M. , Jimenez E. A. , Przybysz-jarnut J. P. , Horesh L. , Douma S. G. , van den Hoek P. J. , Conn A. , Mello U. T.
Published: June 2012

Time-lapse (4D) seismic attributes can provide valuable information on the fluid flow within subsurface reservoirs. This spatially-rich source of information complements the poor areal information obtainable from production well data. While fusion of information from the two sources holds great promise, in practice, this task is far from trivial. Joint Inversion is complex for many reasons, including different time and spatial scales, the fact that the coupling mechanisms between the various parameters are often not well established, the localized nature of the required model updates, and the necessity to integrate multiple data. These concerns limit the applicability of many data-assimilation techniques. Adjoint-based methods are free of these drawbacks but their implementation generally requires extensive programming effort. In this study we present a workflow that exploits the adjoint functionality that modern simulators offer for production data to consistently assimilate inverted 4D seismic attributes without the need for re-programming of the adjoint code. Here we discuss a novel workflow which we applied to assimilate production data and 4D seismic data from a synthetic reservoir model, which acts as the real - yet unknown - reservoir. Synthetic production data and 4D seismic data were created from this model to study the performance of the adjoint-based method. The seamless structure of the workflow allowed rapid setup of the data assimilation process, while execution of the process was reduced significantly. The resulting reservoir model updates displayed a considerable improvement in matching the saturation distribution in the field. This work was carried out as part of a joint Shell-IBM research project.
Wettability Determination by Equilibrium Contact Angle Measurements: Reservoir Rock- Connate Water System With Injection of CO2
Authors: Shojai kaveh N. , Berentsen C. W. , Rudolph E. S. , Wolf K-H. A. , Rossen W. R.
Published: June 2012

The injection of carbon dioxide (CO2) into depleted gas reservoirs and aquifers offer options for CO2-storage. CO2 sequestration is largely controlled by the interactions between CO2, reservoir fluid(s) in place and rock. In particular, the wettability of the rock matrix is a key factor for the fluid distribution and fluid displacement.

In this study, the wetting behavior of CO2-Bentheimer sandstone-water systems was investigated by means of visual contact-angle measurements. The experiments were conducted in a modified pendant drop cell (PDC) that allows captive-bubble contact-angle measurements at elevated temperatures and pressures. Contact angle measures were peformed with water that was fully (pre)-saturated with CO2. Multiple experiments were performed at constant temperature of 318K and pressures varying between 0.1-12 MPA which represent typical in-situ reservoir conditions. The experimental data shows that the contact angle and the size of the bubble converge to equilibrium in time. During this convergence period, the contact angle and the bubble size generally show a slight change as function of time. This can be contributed to the mass transfer and reduction in density of the CO2 during re-equilibration of the system. The experimental data shows a larger dependency of the contact angle on bubble size than on pressure. However, for bubbles with similar size, contact angle shows a slight increase as a function of pressure. However, for bubbles with similar size, contact angle shows a slight increase as function of pressure. All data shows that Bentheimer-water-CO2 systems remain water-wet even at high pressure.
A Comprehensive Workflow for Assisted History Matching Applied to a Complex Mature Reservoir
Authors: Van Doren Jorn , Van Essen Gijs , Wilson Ove , Zijlstra Ellen
Published: June 2012

Currently a multitude of techniques exist for (computer-)assisted history matching (AHM) of simulation models, each with their merits and limitations. In this paper, it is demonstrated how different AHM techniques can be combined to quickly reveal diagnostics of a subsurface model and to obtain a better model in less time, optimally using the strengths of each method. A completed field application of AHM will be presented, in which several AHM techniques are sequentially used to arrive at a history match on pressures and fluid rates and, equally important, an improved understanding of both the static and dynamic model.

The water flooded field, located in the Middle East, has decades of historical production data from twenty wells and is notoriously difficult to match. The first technique that has been applied involves Design of Experiments to generate proxies followed by Monte Carlo Markov Chain to find the ensemble of scalar parameters that give an improved match. Subsequently, adjoint-based history matching has been used to find the areas in the model that were under-modeled and needed additional attention of the subsurface team members.

Based on the results in this step of the workflow the static model has been improved such that it is consistent with the information in the production measurements. For this field, the AHM workflow has achieved a considerable reduction of history matching time. For general simulation studies this workflow is estimated to result in a time saving of 40% with respect to manual history matching. In addition, it results in an improved match and a better understanding of the static and dynamic subsurface uncertainties.
Integrated Reservoir Studies, Karachaganak Field, Republic of Kazakhstan
Authors: Francesconi A. , Bigoni F. , Albertini C. , Cominelli A. , Catalani C. , Tarantini V. , Imagambetov K.
Published: June 2012

Karachaganak field is one of the largest accumulations of gas-condensate in the world in production since 1985. Located in the northern Pricaspian Basin (Kazakhstan) the field is a Permo-Carboniferous isolated carbonate platform with a hydrocarbon column that resides within different environments of deposition. The distribution of reservoir properties has been largely debated because of both the depositional heterogeneity and the diagenetic overprint.

These uncertainties were assessed by analyzing and integrating the vast amount of geological and production data to build a predictive history matched reservoir model.

Seismic facies analysis, with support from outcrop analogues and integrated with field core and log data, reveals, within stratigraphic intervals, "Depositional Regions" (DRs) that ranges from platform interior bedded deposits to aggrading/prograding mounds, clinoforms, slopes and basin sediments. These DRs were first seismically mapped, identifying field scale heterogeneity, and then petrophysically characterized using geologic and dynamic data.

A sequence of progressively optimized models was built according to geologically meaningful concepts that make use of DRs and critical petrophysical issues (such as enhanced/matrix permeability, sealing barriers and dolomitization) were in parallel addressed. A reference model has been so defined and a history match of remarkable quality has been achieved for this complex heterogeneous reservoir.

The uncertainty was investigated in a pragmatic manner using HM as benchmark. The reservoir uncertainty decreases closer and closer to the wells, hence alternative models scenarios were built by gradually changing DRs petrophysical properties going away from the production wells. Using the distance and the magnitude of the perturbations as control parameters and the quality of history match as selection criterion, we could identify two "end members??. These cases represent possible alternative scenarios both consistent with the geological data and still endorsed by a high quality history match, two reservoir models capable to give a significant spread in the production forecast.
Assisted History-Matching for the Characterization and Recovery Optimization of Fractured Reservoirs Using Connectivity Analysis
Authors: Lima A. De , Lange A. , Schiozer D.
Published: June 2012

An integrated optimization workflow was developed to characterize seismic and sub-seismic fault networks from history-matching. A fractal model of fault networks is optimized via the gradual deformation of stochastic realizations of fault density maps, fault spatial and length distributions. In order to facilitate the history-matching, connectivity analysis tools were developed for characterizing wells-reservoir and well-to-well connectivity. Indeed these connectivity properties usually depend on the fault network realization and may be strongly correlated with the reservoir flow dynamics. Connectivity analyses were performed on a fractured reservoir model involving a five-spot well configuration with four injectors and one producer. The connectivity was estimated from shortest path algorithms applied on a graph representation of the reservoir model. Several reservoir simulations were performed for different fault network realizations to seek correlations between injector-producer connectivity and water breakthrough time. The impact of the fracture properties uncertainties on the wells-reservoir connectivity was estimated via the cumulated connected volume computed for each well. This connectivity measure provides a mean to characterize and classify fault network realizations. Correlations were found between the water breakthrough time and the injector-producer connectivity, thus allowing one to identify the most probable fault network realizations to match the observed water breakthrough time. Finally, for a given fault network realization, it is shown how the oil recovery can be optimized by correlating injectors rates with the injector-producer connectivity. A gain of 3.106 m3 in produced oil was obtained, while retarding the water breakthrough time by 16 years, compared with a case where all injectors have the same rate. The proposed methodology and tools facilitate the history-matching of fractured reservoir, providing consistent reservoir models that can be used for production forecast and optimization.
Coupled Static/Dynamic Modeling For Improved Uncertainty Handling
Authors: Kaleta Malgorzata , van Essen Gijs , Van Doren Jorn , Bennett Richard , van Beest Bertwim , Van Den Hoek Paul , Brint John , Woodhead Tim
Published: June 2012

In the petroleum industry, history-matched reservoir models are used to aid the field development decision-making process. Traditionally, models have been history-matched by reservoir engineers in the dynamic domain only. Ideally, if any changes are required to static parameters as result of history matching the dynamic model, then these should be reflected directly in the static reservoir model, ensuring consistency between the static and dynamic domain. In addition, static model uncertainties are often not evaluated in the dynamic domain, which can result in the detailed modeling of geological features that have little impact on the dynamic behavior of the reservoir or the resulting development decision.

This paper demonstrates a workflow where the reservoir simulator and static modeling package are closely linked to promote a more integrated approach to reservoir model construction, facilitating the interaction between subsurface disciplines. Using either the reservoir simulator or the static modeling package as the platform, the output of the workflow is a sensitivity analysis of the uncertainties related to structure, rock properties, fluids and rock-fluid interactions. Computer-assisted history matching methods (i.e. adjoint-based and Design of Experiments) are used to find the parameter values that result in a history match model. The workflow is described for both a synthetic model and also a reservoir model from a real field case.

This methodology results in improved history-matched models and a better understanding of the static and dynamic subsurface uncertainties and their importance, leading to more informed decision-making. Furthermore, it is anticipated that it will result in faster accomplishment of the history matching studies.

The method presented here can significantly enhance the understanding of the impact of both static and dynamic subsurface uncertainties on development decisions. In addition, it offers a platform where all subsurface professionals involved in reservoir model construction and simulation can more optimally focus their efforts on improving the integrated understanding of their reservoirs.
Complexity of Wettability Analysis in Heterogeneous Carbonate Rocks, A Case Study
Authors: Mohammadlou Mohammadhossein , Mørk Mai Britt
Published: June 2012

Estimation of reservoir wettability and its effect on reservoir fluid flow, hydrocarbon recovery and fluid distribution has been the subject of many researches in recent years and remains one of the major challenges in reservoir characterization. This study examines the reservoir wettability in heterogeneous karstified carbonate rocks from comparison of special core analysis (SCAL) and resistivity index measurements on the core plugs, together with study of nuclear magnetic resonance (NMR) log, and formation pressure obtained by modular dynamic tool (MDT) measurements in the reservoir.

The SCAL test results present moderately water-wet reservoir conditions at the cored intervals of the reservoir. Surveys from resistivity index measurements are in general agreement with the SCAL results. Due to lack of core data in the lower/main part of the reservoir, analysis of the NMR T2 distribution are combined with MDT data to describe the reservoir wettability. The pressure data suggests a water gradient through the reservoir column except for anomalous high pressure values in which corresponds to zones with high resistivity and oil saturations. High oil saturation is not expected in zones where the reservoir has been water flooded (water level rise in the reservoir) after hydrocarbon accumulation. The study of the T2 distribution of these intervals helps to identify the oil wet nature of the larger pores in the reservoir. The surface relaxivity of oil when it wets the pore surface cause a shift in the T2 distribution towards shorter T2sC". The water volume, then, in oil wet pores relaxes as bulk relaxation with longer T2 compared to the water wet case. This study suggest that a combination of the NMR log with MDT data and resistivity logs provides a method to identify wettability characteristics of complex rocks when core plugs are missing.
Optimizing Well Placement With Quality Maps Derived From Multi-fidelity Meta-models
Authors: Le Ravalec Mickaele
Published: June 2012

Quality maps have been introduced as an efficient and expedient tool to select infill well placements, quality being a measure of how good an area is expected to be for production. Even though this tool is less CPU-time consuming than optimization algorithms, it still requires a significant number of flow simulations. Solving the computation time problem is even more challenging when dealing with geological uncertainty. In this case, quality maps have to be determined for several possible reservoir models, which clearly induces an increase in the number of flow simulations to be performed. In this paper, we first investigate the impact of geological uncertainty on quality maps. Then, we compare the potential of kriging and multi-fidelity meta-models for approximating quality from a reduced number of flow simulations. The main interest of the multi-fidelity technique is its ability to incorporate data at different levels of resolution. Thus, you can balance the flow simulations performed at the fine scale by flow simulations at the coarse scale. The latter being cheaper to evaluate, the computational overburden is considerably reduced. This approach turns out to be promising for the case studied.
In-Well, Optical, Strain-Based Flow Measurement Technology and Its Applications
Authors: Ünalmis Ö. Haldun , Trehan Sumeet
Published: June 2012

In-well flow measurement remains as one of the most difficult tasks in the oil and gas industry, mainly due to the challenging conditions of the downhole environment. When made successfully, however, it plays a major role in monitoring and optimizing well performance, especially for the wells equipped with advanced completion devices. The increasing demand for in-well flow measurement is also driven by other factors including zonal production allocation in multizone completions as well as reliable commingled production, reduction of surface well tests and facilities, and detection of production anomalies.

This paper provides a closer look at one of the state-of-art in-well flow measurement technologies: optical, strain-based, phase flow rate measurements via turbulent structure velocity and sound speed of the turbulent flow. It is an introduction to how this flow measurement technology works and how it is applied to different flow applications from single-phase injectors to multiphase producers. Specific field examples representing different flow applications are also referenced to published material. The strong and weak points of the technology are explored, and in the process, an operation envelope is produced for the use of this technology. The system response to the presence of advanced completion devices are also discussed, guidelines are given, and recommendations are made based on field and lab tests.

Understanding a technology’s strong and weak points before implementation is essential to ensuring that informed and successful decisions can be made concerning its use for a given application. This process is often mutually beneficial to both operators and equipment manufacturers since collaborations can lead to advancement of technology and, as a result, provide even more reliable solutions.
Reducing Reservoir Uncertainties Using Advanced Wireline Formation Testing
Authors: Loi D. , Mazzoni S. , venturini S. , Baio C. , Borghi M , Baldini D. , Italiano F. , Cantini S.
Published: June 2012

Several offshore gas fields are present in Adriatic Sea (Italy), producing since the 60s from multilayer metric sand reservoirs. The declining production in these mature fields is normally offset by drilling new deviated wells. Recent technology evolution shifted the focus from metric reservoirs to thinly laminated intervals (thin beds), until now not produced due to difficulties in identifying gas bearing zones.

While gas identification in metric reservoirs can be normally achieved with standard petrophysical measurements, thin beds are challenging since lamination thickness is half inch or less and even advanced petrophysical logs struggle in discriminating gas from water in this environment. Conventional pressure gradient approach also does not work, since thin beds are often overpressurized and pressures are supercharged due to low mobility.

A new wireline formation testing approach for thin beds to discriminate gas from water zones was introduced, using a dual packer string with downhole fluid analysis capabilities, including fluid density measurement. This provided the possibility of testing very low permeability zones with high uncertainties in saturations. Dual packer tests were also successfully carried out in the underlying shale formation never considered before a real reservoir, revealing potential for gas production. The possibility to verify gas presence in zones with high uncertainties saved the cost of multiple well tests, optimized the completion strategy of the different reservoirs and allowed to increase the field production and reserves, reducing at the same time uncertainties in reservoir model.

Four jobs with dual packer and downhole fluid analysis to test thin beds were performed so far in Barbara NW, Barbara and Clara Fields, resulting in added gas reserves estimated in 2 Billions Sm3 and gas production higher than the one at fields startup several years ago. This is a remarkable result for development wells in a mature environment (balanced exploration), maximizing asset value. Based on these results, several gas fields producing today from metric reservoirs will be revisited in the very near future in order to start production from thin beds, untouched until now, with the advanced wireline formation testing approach described in this paper playing a key role.
Fracture Characterization Through Rate Correlation Analysis
Authors: Heffer Kes
Published: June 2012

Statistical correlations in flowrate fluctuations between wells from many fields appear to bear out the expectation that the hydraulic conductivities of faults and fractures in reservoirs can be influenced by geomechanical perturbations due to production operations: the fluctuations are characterised by high correlations over very large separation distances between wells; and those correlations appear to be stress-related and fault-related. An entirely separate relationship derived from observations in multiple fields is a strong bias of directionalities shown by injected fluids towards the local orientation of modern-day major principal horizontal principal stress axis (SHmax). These two sets of independent field observations provide mutually supporting observational evidences for the general geomechanical sensitivity of faults and fractures. However, whilst peaks in flowrate correlations are observed at about 30° to SHmax, the preferred flooding directionalities are at smaller angles to SHmax. A recently proposed machanism is able to explain the orientational relationships in both sets of data. It involves interacting, stress-aligned, compliant micro-cracks near a critical density; there is a large background of observations of shear-wave splitting in many types of formations that supports the prevalence of such micro-cracks. As a practical low-cost tool, analysis of flowrate correlations can provide valuable information about the major reservoir pathways as an adjunct to reservoir characterisation studies. This information can aid history-matching of reservoir models, particularly those involving fractures. The technique is also well-suited to monitoring reservoir behaviour in time-lapse fashion.
A Proposed Workflow for Disposal of CO2 using CO2 Hydrate
Authors: Rajnauth J.
Published: June 2012

Carbon dioxide (CO2) is an important greenhouse gas because it transmits visible light but absorbs strongly in the infrared. It is mainly generated from the combustion of fossil fuels or vegetable matter, among other industrial processes such as cement production and ammonia plants. CO2 emitted from burning fossil fuels is believed to be a major contributor to the amount of CO2 levels in the atmosphere contributing to global warming.

Hydrate technology can be used to capture CO2 gas in the form of hydrates. In this technology CO2 and water are combined at certain conditions of temperature and pressure to form a hydrate, and then transported and released at great depths into the ocean. Disposal of CO2 in the form of hydrates in the sea is a great potential as the ocean is vast and occupies 70% of the earth's surface. Numerous power plants and petrochemical plants are located near the coastline and hence there is easy access to the ocean. The CO2 hydrate formation as a CO2 disposal method may potentially offer significant savings in CO2 disposal because of minimal cost of CO2 capture.

This paper proposes a work flow for disposing of CO2. The model describes the sequence of operations for CO2 capture and disposal using CO2 hydrate. A typical example would be used to describe the workflow from CO2 emitted to CO2 hydrate disposal. CO2 hydrate is denser than seawater and therefore CO2 hydrate deposited in the ocean will sink to the seabed as long as the disposal site is within the hydrate formation envelope.
Understanding the True Potential of a Major Reservoir Sabriyah (Upper Burgan) of Kuwait Oil Company
Authors: Al Shammari Hanaa , Bora Anup , Singh B B , Mishra Kumar
Published: June 2012

Kuwait Oil Company is presently working on number of fronts to increase its reserve base to meet the future strategic requirements of the country. The major challenge is to continuously work on improving the overall recovery from the existing reservoirs. For achieving this goal, Reservoir Management Technical Limit study (RMTL) process was undertaken to estimate the true potentials of a number of reservoirs of KOC which are under various stages of development.

RMTL is a structured, facilitated, documented process at which multi-disciplinary teams and independent experts review the depletion plan for a reservoir and identifying reserve growth opportunities to its technical limit. The RMTL study was carried out to assess the potential of Sabriyah (Upper Burgan) reservoir in North Kuwait asset of Kuwait Oil Company. This reservoir is currently in the second stage of development with activities like development drilling, water injection for pressure maintenance.

In order to assess the viability of different EOR processes and eliminate technically unviable process, the analytical screening was done. Finally, a few representative pattern elements from the full field simulation model were extracted for use in the EOR screening. The EOR screening exercise has shown potential for low salinity water flood, surfactant polymer and potentials for miscible CO2 injection. Incremental recovery factors up to 13% are predicated compared with conventional water flooding. These studies have given a direction to the company to decide on economically viable EOR processes in different reservoirs of Kuwait.
Multidisciplinary Approach for Novel Application of Formation-pressure-while-drilling Service in High Temperature (160 Deg.C) Low Permeability Carbonate
Authors: Bruni Corrado , Odumboni Idowu , Sellami Besma , Turner Marcus , Sanguinetti Marco , Kazmer Jorge
Published: June 2012

The Abiod formation is the principal target in the Miskar field, offshore Tunisia. Consisting of fractured geomechanically stressed carbonate with a measured matrix permeability as low as 0.1 mD. The formation dates from Campanian to lower Maastrichtian and forms a horst structure. The formation has been under production since 1996.

Obtaining formation pressure data was considered critical for determining the magnitude of depletion from production, well-to-well comparisons for vertical and lateral connectivity, forward modeling, completion decisions, and refinement of the field development plan. Historically, this has been a challenge with conventional wireline (WL) formation testers for the following reasons: Severe depletion and well deviation causing differential stickingHigh temperatures (150 to 195° C) at the limit of tool electronicsLow permeabilityFractures and breakouts that can impact seal success

This was overcome with a systematic multidisciplinary approach. After review of historical formation testing data, and influence on seal success with probe vs. packer elements, it was decided to apply formation-pressure-while-drilling (FPWD) technology. The key questions with FPWD in this environment are: Can we achieve a good transient profile and what is potential impact of supercharging? These questions were addressed with advanced prejob modeling, which enabled determination of an optimized pretest configuration and testing procedure to minimize potential supercharging effects.

While drilling, stage-in procedures were used, and mud logging total gas data were gathered to identify areas of liberated gas. Pre-run wireline petrophysical data were gathered to characterize the Petrophysical properties of the reservoir and to calculate an intrinsic permeability profile. Ultrasonic borehole images and caliper data were used to determine the principal horizontal stress directions, fracture frequency, and orientation and to confirm the stratigraphic dipping of the structure. Combined, this information allowed a focused orientation of the FPWD probe and optimal station selection avoiding fractures and breakouts.

This novel approach resulted in 100% seal success, >50% improvement. Four days of rig time were saved, and the required data were obtained.
Use of Water Chemistry Data in History Matching of a Reservoir Model
Authors: Arnold D. , Vazquez O. , Demyanov V. , Christie M. A.
Published: June 2012

Produced Water Chemistry (PWC) has been included in the history matching of reservoir simulations. Generally, in conventional history matching, the water chemistry is not considered as an extra constraint. The chemistry of the different types of water in a reservoir, such as aquifer, connate and seawater is very different, and can be traceable. Produced Water Chemistry is the main source of information to monitor scale precipitation in oil field operations.

The objective of this paper is to evaluate the effect of adding produced water chemistry information as an extra constraint history matching a modified version of the PUNQ-S3 reservoir model. The PUNQ-S3 model is a synthetic benchmark case that has been used previously for history matching and uncertainty quantification. Conventional historical production data (gas, oil rates and pressure) from six production wells are supported by the water chemistry tracer data from the wells that produce water in the history period. The different types of water are traced through their distinctive chemistries, namely aquifer, connate (formation) and sea (injection) water. Geological model is matched by varying porosity and permeability, both horizontal (kh) and vertical (kv) according to the prior beliefs about the reservoir geology (layering, spatial correlation and anisotropy).

Two history matching (HM) scenarios are considered: including and not-including the Produced Water Chemistry (PWC) as an extra matching constraint. Stochastic Particle Swarm Optimization (PSO) algorithm is used to generate ensembles of history matched models, which characterise the uncertainty of the reservoir prediction. Comparison of the two scenarios reveals potential value of adding PWC data in history matching that allows achieving better matched models and ensuring diversity of HM models, which is essential for robust uncertainty quantification of the predictions.
Dynamic Capillary Pressure Curves from Pore-Scale Modelling in Mixed-Wet Rock Images
Authors: Zhou Y. , Helland J. O.
Published: June 2012

In reservoir multiphase flow processes with high flow rates, both viscous and capillary forces determine the pore-scale fluid configurations, and significant dynamic effects could appear in the capillary-pressure/saturation relation. We simulate dynamic and quasi-static capillary pressure curves for drainage and imbibition directly in SEM images of Bentheim sandstone at mixed-wet conditions by treating the identified pore spaces as tube cross-sections. The phase pressures vary with length positions along the tube length but remain unique in each cross-section, which leads to a nonlinear system of equations that are solved for interface positions as a function of time. The cross-sectional fluid configurations are computed accurately at any capillary pressure and wetting condition by combining free energy minimization with a menisci-determining procedure that identifies the intersections of two circles moving in opposite directions along the pore boundary. Circle rotation at pinned contact lines accounts for mixed-wet conditions. Dynamic capillary pressure is calculated using volume-averaged phase pressures, and dynamic capillary coefficients are obtained by computing the time derivative of saturation and the difference between the dynamic and static capillary pressure. Consistent with previously reported measurements, our results demonstrate that, for a given water saturation, simulated dynamic capillary pressure curves are located at a higher capillary level than the static capillary pressure during drainage, but at a lower level during imbibition, regardless the wetting state of the porous medium. The difference between dynamic and static capillary pressure becomes larger as the pressure step applied in the simulations is increased. The model predicts that the dynamic capillary coefficient is a function of saturation and independent of the incremental pressure step, which is consistent with results reported in previous studies. The dynamic capillary coefficient increases with decreasing water saturation at water-wet conditions, whereas for mixed-to oil-wet conditions it increases with increasing water saturation. The imbibition simulations performed at mixed-to oil-wet conditions also indicate that the dynamic capillary coefficient increases with decreasing initial water saturation.

The proposed modelling procedure provides insights into the extent of dynamic effects in capillary pressure curves for realistic mixed-wet pore spaces, which could contribute to improved interpretation of core-scale experiments. The simulated capillary pressure curves obtained with the pore-scale model could also be applied in reservoir simulation models to assess dynamic pore-scale effects on the Darcy scale.
History-matching with Ensemble-Based Methods: Application to an Underground Gas Storage Site
Authors: Gervais V. , Le Ravalec M. , Heidari L. , Schaaf T.
Published: June 2012

This paper shows the application of two ensemble-based assimilation methods, the Ensemble Kalman filter (EnKF) and the Ensemble Smoother (ES), to constrain an underground gas storage site to well pressure data. The EnKF is a sequential data assimilation method that provides an ensemble of models constrained to dynamic data. It entails a two-step process applied any time data are collected. First, production responses are computed for every model within the ensemble until the following acquisition time. Second, models are updated using the Kalman filter to reproduce the data measured at that time. The EnKF has been widely applied in petroleum industry. More recently, the ES was successfully applied to a real field case. This method is also based on the Kalman filter, but the update is performed globally over the entire history-matching period: values simulated at assimilation times are considered all together in the update step. The uncertain parameters considered here are the porosity and horizontal permeability values populating several layers of the geological model. Applying both the ES and EnKF methods, the spread within the ensembles is reduced and the predictions based on the ensembles of updated petrophysical distributions get closer to the pressure data corresponding to the history-matching and prediction periods.
A Comparative Study of Reduced Variables Based Flash and Conventional Flash
Authors: Michael L. Michelsen , Yan Wei , Stenby Erling H.
Published: June 2012

Speeding up flash calculation is a central issue in compositional reservoir simulations since phase equilibrium calculation is the most time-consuming part in those simulations. The reduced variables methods, or the reduction methods, reformulate the original phase equilibrium problem with a smaller set of independent variables. Various versions of the reduced variables methods have been proposed since the mid 80’s. The methods were first proposed for cubic equations of state (EoS) with zero binary interaction parameters (BIPs) and later generalized to situations with non-zero BIP matrices. Most of the studies in the last decade suggest that the reduced variables methods are much more efficient than the conventional flash method. However, Haugen and Beckner questioned the advantages of the reduced variables methods in their recent paper (SPE 141399). A fair comparison between the reduced variables based flash and the conventional flash is not straightforward since the former is difficult to be formulated as unconstrained minimization and involves more complicated composition derivatives. With the recent formulations by Nichita and Graciaa (2010), it is possible to code the reduced variables methods without extensive modifications of Michelsen’s conventional flash algorithm. A minimization based reduced variables algorithm was coded and compared with the conventional minimization based flash. A test using the SPE 3 example showed that the best reduction in time was less than 20% for the extreme situation of 25 components and just one row/column with non-zero BIPs. A better performance can actually be achieved by a simpler implementation directly using the sparsity of the BIP matrix.
Improved Mobility Calculation for Finite Element Simulation
Authors: Abushaikha Ahmad S. , Blunt Martin J. , LaForce Tara , Gosselin Olivier R.
Published: June 2012

We implement a novel up-winding scheme for finite element mobility calculation using the computed velocities in a finite element finite volume (FEFV) unstructured-mesh simulator. In FEFV numerical method, the pressure and transport equations are decoupled. The pressure is calculated using finite elements, and the saturation is calculated using finite volumes. Each element is shared between several control volumes -- three for triangles and four for tetrahedrals. Consequently, the saturations used in calculating element mobilities - hence updating pressure - are unclear. Some researchers use the average value between the elemental control volumes, or the integration points of the finite elements. For three-dimensional spherical flow, this does not produce accurate saturations profiles when compared to the Buckley-Leverett reference solution.

In this paper, we present a new formulation to calculate the FE mobility. We use the velocity vector, which is piece-wise constant in first order elements, to find the upstream saturation–where the tail of velocity vector intersects an element. This novel approach produces more accurate saturation profiles than previous conventional method, and it better models multi-phase displacements in complex reservoirs. It can be easily implemented in current FEFV based simulators.
Considerations on of Drillpipe Dynamics with Actual Drilling Data
Authors: Inoue Tomoya , Kyo Masanori , Sakura Koji , Senga Hidetaka
Published: June 2012

The scientific drilling vessel Chikyu was designed to have the capability to drill down to 10,000 m total vertical depth and to obtain core samples. To reach such deep drilling and to recover scientifically worthy core samples, it is important to know the drill pipe dynamics using the actual drilling data for strength evaluation of the drill pipe and for control of a drill bit.

To reach such deep drilling, a fine strength evaluation is mandatory because there is little margin. So, the estimation of dynamic tension due to vessel heave motions is necessary. During the design phase, strength evaluation of the drill pipe is conducted under several assumptions. To ensure the strength of the drill pipe, it is important to utilize data acquired from actual drilling operations and to verify the analysis model. Furthermore the core recovery rate is affected by the variation of the weight on bit caused by the propagation of the vessel heave motions. Therefore, a heave compensating system will be used and it is very important to evaluate the performance.

Thus, the authors have acquired the drilling data including the vessel motions, the hook load variations and the motion of the heave compensator. And analysis with actual drilling data shows the dynamic tension that was actually exerted and the basic performance of the heave compensator. This paper described that the dynamic tension considering influence of the compensator and also the performance of the heave compensator from the viewpoints of following capability including a phase difference. Actual drilling data provided the worthy information on the drill pipe dynamics. The considerations will be utilized for future operations such as Tohoku Earthquake Drilling Program and Nankai Trough drilling programs and also for future technical development.
A Parallel Streamline Simulator for Integrated Reservoir Modeling on a Desktop
Authors: Gaupaas Morten , Bratvedt Frode , Khataniar Sanjoy Kumar , Primera Alejandro , Ruan Feng P
Published: June 2012

Desktop computing is undergoing a revolution with parallel processing on workstations. Parallel streamline simulators have been developed for shared memory architecture systems. In this paper, we discuss the implementation and performance analysis of a shared memory architecture commercial parallel streamline simulator based on native threading technology for both Windows® and Linux® operating systems.

In general the streamline simulation algorithm is relatively straightforward to parallelize, however, there are several challenges that require special attention in order to avoid computing bottlenecks and inconsistent results. Repeatability of parallel simulation results is a well-known challenge. A data-accumulation scheduling algorithm designed to ensure repeatable results independent of the number of processing units has been implemented. The algorithm is supplemented by an efficient loadbalancing algorithm, to minimize processor idle time.

Parallel scalability for various model characteristics and streamline solver options is analyzed. We have observed almost linear scalability up to 10 threads and a speed up factor of three to seven for simulation runs using a 1D explicit upwind finite difference solver to solve the transport problem along streamlines. The front tracking solver is inherently fast and does not gain significantly from parallelization. The run time of a serial simulation using the front-tracking solver is less than that of a parallel explicit solver run using up to 12 threads. The memory consumption of the front tracker is slightly higher than the explicit solver but overall streamline simulations are very memory efficient, enabling large geo-scale models to be simulated efficiently on 64-bit workstations. Complex three-phase blackoil simulation problems require a larger number of timesteps steps and speedup degrades as run time becomes dependent on the efficiency of the pressure solver. The results produced by our parallel streamline simulator are repeatable for any number of threads, and the algorithm used to achieve repeatability has little impact on performance.
A Versatile Representation of Upscaled Relative Permeability for Field Applications
Authors: Lomeland Frode , Hasanov Bashir , Ebeltoft Einar , Berge Marianne
Published: June 2012

A suitable approach to achieve a fit-for-purpose model for field application is upscaling of reservoir properties. However, upscaling of saturation functions like relative permeability is still a source of debate and is frequently omitted due to its inconvenient complexity. Upscaling of these functions, whether by steady-state methods or other techniques, typically generates a complex myriad of relative permeability curves that is challenging to handle pragmatically. This study investigates whether a three-parameter correlation of relative permeability is able to represent the saturation function for fine grid simulation models with the most common heterogeneities, coarse grid simulation models with upscaled properties in addition to verify two-phase core-flow experiments.

To demonstrate the applicability of two flexible three-parameter correlations at the field simulation scale, we have utilized three synthetic fine-scale models with the most common heterogeneities: a severe thief zone, upward coarsening and downward coarsening. All simulation cases use a down-dip water injector and an up-dip oil producer. Excellent matches are obtained by history matching on the parameters of the coarse grid correlations in all cases.

The flexibility of the correlations will, opposed to the restricted single-parameter Corey (1954) representation, enable a versatile, pragmatic and satisfactory upscaling for coarse grid blocks when used in combination with any well-known upscaling method. The benefit is a limited number of parameter arrays as opposed to numerous rather inconvenient tables. The proposed parametric representation of upscaled relative permeability is applicable to immiscible recovery methods in general.

Implementation of the proposed three-parameter correlations of the relative permeability in the algorithm of full field simulators will overcome the representation challenges of present published upscaling methods.

Upscaling of each coarse grid block individually can then be handled pragmatically, and hence provide fit-for-purpose models for field application.