bluuebunny/crossref_metadata_2025 huggingface dataset:
Interventions with Reliable Execution in Hostile Environments
Authors: Schwanitz Brian , Henriques Kristine
Published: June 2009

A light weight intervention technique utilizing electric wireline has emerged as an alternative to existing well intervention methods. Tractor technology enables high speed, low HSE impact and a high degree of precision in production enhancing interventions in onshore and offshore wells. Wireline tractor technology eliminates the limitation on traditional wireline by extending the reach of the wireline into a high angle or horizontal part of the well bore, enabling access to the entire length of the well.

Interventions in challenging conditions such as subsea, deepwater, extended reach, high-yield, heavy oil and deepwater are also enabled whether the hole angles are highly deviated or not. For instance, where slick line or coiled tubing (CT) operations below 20,000 ft can be risky and costly, tractor technology offers a time and cost-efficient alternative for valve manipulation, sand clean out and scale milling. Furthermore, interventions have been performed in high temperature wells (388°F), high pressure (>20,000 psi), ERD wells (>30K ft) and high deviations (130°) wells.

Wireline tractor services can be mobilized in a matter of hours and only require a crew of from two to four people, depending on the operation. Transportation can be done in a helicopter to avoid the cost and time of mobilizing a full CT spread such as when cleaning and milling operations are performed without surface fluid handling logistics. Further, lightweight interventions with tractor technology combined with low surface impact left on the environment, allows mobilizations in eco-sensitive regions where heavy methods are not permitted due to the irreversible environmental damage that would be caused.

This paper will present case studies where the HSE impact was significantly reduced by employing lightweight intervention techniques through tractor related mechanical services. One case will be a recent operation of milling barium sulfate scale on electric wireline and removing the cuttings in the same run in the hole. The second case will be milling out a cast iron bridge plug on electric wireline and the third will highlight the world's first wireline tractor intervention from a subsea intervention ship, which provided a much lighter solution for the operator.
Production Optimization Under Uncertainty
Authors: Nogueira Pedro De B. , Schiozer Denis J.
Published: June 2009

This work presents a methodology that gives more accuracy to the handling of uncertainty in optimization process of production strategies. In this methodology, pessimistic, intermediate and optimistic realizations for the geological model and the economic environment can be considered. Differently from other methodologies, this consideration is made simultaneously during the optimization process. The process is guided by the expected monetary value (EMV) of project. It gives a greater adaptability to the optimized production strategy.

An algorithm that carries out the EMV of a production strategy for each step of the optimization was developed. This algorithm performs the interconnection between flow simulation and economic analyses, necessary to calculate the EMV of a production strategy. It is called at every time where the optimization process requires the objective-function evaluation. In this work the methodology proposed by Nogueira and Schiozer, 2009 for production strategies optimization based on genetic algorithms is utilized.

The performance of the proposed methodology is compared with the performance of a conventional methodology of production optimization under uncertainty. A case with three geological models and three economic scenarios is studied. The optimized strategy presents more adaptability to the possible variations, showing a good performance in all adopted contexts. Although the proposed methodology represents a more accurate process than the conventional methodology, there is a decrease in the number of flow simulations required to optimize the production strategy. The proposed methodology is shown as a viable alternative for handling of uncertainties for optimization process of production strategies.
Integration of NMR and SCAL to Estimate Porosity, Permeability and Capillary pressure of Heterogeneous Gas Sand Reservoirs
Authors: Hamada G. M.
Published: June 2009

Analysis of heterogeneous gas sand reservoirs is one of the most difficult problems. These reservoirs usually produced from multiple layers with different permeability and complex formation, which is often enhanced by natural fracturing. Therefore, using new well logging techniques like NMR or a combination of NMR and conventional open hole logs, as well as developing new interpretation methodologies are essential for improved reservoir characterization. Nuclear magnetic resonance (NMR) logs differ from conventional neutron, density, sonic and resistivity logs because the NMR measurements provide mainly lithology independent detailed porosity and offer a good evaluation of the hydrocarbon potential. Integration of NMR logs, other open hole logs and SCAL minimizes uncertainties in the determination of formation porosity, permeability and capillary pressure curve.

This paper focuses on determination of three petrophysical parameters of heterogeneous gas sand reservoirs which are Determination of DMR porosity, fDMR, it is deduced from NMR porosity and density porosity; NMR permeability, KBGMR, it is based on the dynamic concept of gas movement and bulk gas volume in the invaded zone and Capillary pressure, it is derived from relaxation time T2 distribution.
Oil Recovery Improvement Using CO2-Enriched Water Injection
Authors: Riazi Masoud , Sohrabi Mehran , Jamiolahmady Mahmoud , Ireland Shaun , Brown Christopher
Published: June 2009

CO2 injection is increasingly considered as having potential applications as a possible enhanced oil recovery (EOR) process for oil reservoirs. However, poor sweep efficiency has been a problem in many CO2 floods and hence, the injection strategies like WAG (water-alternating-gas) injection have been proposed and applied in the field as a way to mitigate the problem. An alternative injection strategy is CO2-enriched (carbonated) water injection (CWI).

This paper presents the results of an integrated experimental and theoretical study on the application of CO2-enriched water flooding for enhanced oil recovery. Direct flow visualisation experiments were carried out using high-pressure transparent porous media. The results of our visualisation experiments demonstrate that CWI, compared to unadulterated water injection, improves oil recovery. The additional oil is recovered as a result of an improved sweep efficiency, due to the oil swelling, viscosity reduction and coalescence of the isolated oil ganglia as a result of CO2 diffusion. This injection strategy is particularly attractive in waterflooded oil reservoirs in which high water saturation adversely affects the performance of conventional CO2 injection methods. CWI can also be carried out in combination with reservoir depressurisation carried out subsequent to CWI or in a cyclic manner in which carbonated and plain water cycles are injected in succession.

The results of a mathematical model are also presented which honours our experimental observations and simulates the dynamic process of oil swelling and shrinkage due to CO2 transfer during Carbonated water and plain water injection.
Automated characterization of fracture conductivities from well tests inversion
Authors: Bruyelle Jérémie , Lange Arnaud
Published: June 2009

Methodologies and numerical tools are available (i) to construct geologically-realistic models of fracture networks, (ii) to turn these models into simplified conceptual models usable for field-scale simulations of multi-phase production methods. However a critical intermediate step remains that of validating the geometry of the geological fracture network and characterizing it in terms of flow properties. This characterization step involves the calibration of available field data, e.g. well tests, with simulated data. It is usually an ill-posed problem: available data are insufficient to fully characterize the fracture properties, for instance. Therefore prior estimates of these properties are necessary, but these estimates are usually uncertain, resulting in a wide range for the properties values to be investigated. This paper presents a complete methodology to address this inverse problem: (1) a covariance matrix adaptation-evolution strategy is used to explore efficiently the properties space; (2) the latter optimizer is coupled with a surface response methodology in order to detect several solutions simultaneously, and to estimate the properties global sensitivities to field data during optimization. An application involving a horizontal well test and a fracture network with two sets of systematic joints and one fault set is presented. For a given realization of the fracture network geometry, it is shown that the optimization of fracture conductivities via the present methodology results in the characterization of two distinct, although both data-consistent below a 0.1% error in pressure, sets of solutions for the joints conductivities. The fault set conductivity is shown to have a low sensitivity to the well test data. As sensitivities are estimated during optimization, by using a surface response methodology and the Sobol decomposition technique, it is possible to reduce the optimization cost by eliminating low sensitive parameters during the optimization process. The effectiveness of the methodology to characterize physically meaningful and data-consistent fracture properties is discussed further.
Uncertainty Analysis Applied to Biogenic Reservoir Souring Simulation
Authors: De Siqueira Alexandre Guedes , Araujo Carlos Henrique Vieira , Reksidler Rodrigo , Pereira Marcio de Castro
Published: June 2009

In petroleum industry, uncertainty analysis is frequently used to define the expected probabilistic range of oil, gas and water production profiles. This paper describes a new application, aiming to estimate the probabilistic concentration range of hydrogen sulphide (H2S) in produced fluids. Several oilfields undergo increasing concentrations of produced H2S, typically during seawater injection for secondary recovery. Usually, such toxic and corrosive compound is generated by Sulphate- Reducing Bacteria (SRB). Bacterial activity is not favoured in the reservoir original environment, but can become feasible after water injection, mainly because injected water can have high sulphate contents, can cool certain regions of the reservoir, and can dilute bacterial inhibitory compounds in formation water.

Reservoir souring modelling is useful to anticipate decisions, either by preventive measures or a mitigation strategy, to avoid exposition of people, environment and installations to serious hazards. Inasmuch there are significant uncertainties in various simulation parameters, H2S concentrations presented as a probabilistic range – instead of a deterministic value – can be worthy to fine-tune the acceptable level of risk tolerance in the decision-making process.

Each field development scenario relates to a specific sensitivity to the simulation variables and probabilistic ranges are, in some cases, very wide. Commonly, not only microbial-related parameters are relevant: part of the biogenerated H2S is retained in the reservoir, due both to adsorption/reaction with rock minerals and to partition of H2S in water and oil phases.

Since 2005, the mentioned probabilistic approach is used in Petrobras to base decisions that have a large impact on the field development overall costs.
Case History: A Robust Point-the-Bit Rotary Steerable System with At-Bit Imaging and 3D Geosteering Service Integral to Optimal Wellbore Placement in a Complex Thin Sand Reservoir
Authors: Kok Keng H. , Hughes-Jones Huw , Chavez Ernie , Aziz Khairul Azmee Abdul , Yusof Khazimad , Lambert Mark
Published: June 2009

This paper describes the optimization of a well placement in a 4 m thin complex sand reservoir, using a point-the-bit rotary steerable system, real-time LWD imaging, and 3D geosteering software in well Chermingat A02 drilled by Newfield Peninsula Malaysia Inc. Real-time, at-bit gamma images 1 m from the bit proved crucial in providing early structural interpretation for geosteering decisions. Higher resolution density images further refined the structural interpretation. A geosteering consultancy service, based in the customer's office, provided the subsurface team with guidance throughout the geosteering process, which led to the successful delivery of the well objectives.

The advanced, intuitive 3D geosteering software was used to create a geological model based on offset data and geological surfaces. This local geological model was updated continuously throughout the drilling process, based on the best match between modeled and actual logging-while-drilling (LWD) sensor responses, to reveal local bed dip, bed thickness, and faults. Changes in the well trajectory were seamlessly communicated to the directional drillers on-the-fly by means of a two-way down linking system to the point-the-bit rotary steerable system, while on-bottom drilling ahead continued with no drilling interruptions. This new level of efficiency, using at-bit images immediately integrated into an intuitive geological modeling package with full support from the geosteering advisors, resulted in rapid geosteering decisions with no downtime waiting for a decision from town. The team achieved 500m (1,640 ft) MD of high quality reservoir, thus meeting the objective of the original well plan.

This strategy and operational efficiency resulted in a cost savings of $812,000 (USD). The methodology, lessons learned, and experience gained from this well were applied successfully in the next drilling campaign in East Belumut A02 and in subsequent wells on the East Belumut platform.
Evaluation of Extended Seawater Injections Impact on Waste Injection Pressure Response and Waste Disposal Capacity
Authors: Gumarov S. , Ovalle A. , Shokanov T. , Park G. , Simmons S.
Published: June 2009

The injection of drilling generated waste into a selected subsurface formation has evolved into the most preferred waste disposal technology in terms of environmental compatibility and cost effectiveness, especially for remote and environmentally sensitive areas. The main principle of waste injection (WI) is the initiation of hydraulic fracture and the placement of solids within the created fractures through the high-pressure pumping of slurry batches. The fracture propagation is governed mainly by in-situ stresses. As injection progresses solids accumulation in the fracture leads to an increase of in-situ stresses within the injection zone causing a build-up of injection pressure. As allowable injection pressure is often limited by equipment, the undesirable or rapid injection pressure build-up could jeopardize the operational life of an injection well and limit its waste disposal capacity.

This paper introduces a new approach to a regular seawater injection by investigating the relationship between pressure behavior and seawater injection. Displacement of slurry from the tubing by seawater over flush is carried out routinely in WI operations worldwide. However, never before it was considered as a pressure maintenance tool. The authors describe the impact of continuous seawater injection on injection pressure through the lifetime of three waste injectors. The injection pressure behavior before, during and after continuous seawater injection was reviewed using downhole measured data. It was noticed that regular seawater over-displacements during the continuous time periods between slurry injections reduced injection pressure considerably. Consequently, a thorough evaluation was initiated to investigate the impact of extended seawater injection on in-situ stresses and its potential advantage in maintaining the injection pressure within lower limits. 

Considering the novelty and value of study for expanding worldwide WI operations, this paper presents the new approach to seawater injection as an injection pressure and disposal capacity maintenance tool.
Natural and Conventional Tracers for Improving Reservoir Models Using the EnKF Approach
Authors: Huseby Olaf , Valestrand Randi , Nævdal Geir , Sagen Jan
Published: June 2009

Natural tracers (geochemical and isotopic variations in injected and formation waters) are a mostly unused source of information in reservoir modeling. On the other hand, conventional inter-well tracer tests are an established method to identify flow-patterns. However, they are typically underexploited, and tracer-test evaluations are often performed in a qualitative manner, and rarely compared to simulation results in a systematic manner. To integrate natural and conventional tracer data in a reservoir modeling work-flow, we use the ensemble Kalman Filter (EnKF) that has recently gained popularity as a method for history matching. The EnKF includes online update of parameters and the dynamical states. An ensemble of model representations is used to represent the model uncertainty. In this paper we include conventional water tracers, as well as natural tracers (i.e. geochemical variations), in the EnKF approach. The methodology is demonstrated by estimating permeability and porosity fields in a synthetic field-case, based on a real North Sea field-example. The results show that conventional tracers and geochemical variations yield additional improvement in the estimates, and that the EnKF approach is well suited as a tool to include this information. The principal benefit from the methodology is improved models and forecasts from reservoir simulations, through optimal use of conventional and natural tracers. Some of the natural tracer data, scale forming ions and toxic compounds, e.g., are monitored for other purposes and exploiting such data can yield significant reservoir model improvement at a small cost.
Ant Colony Optimization for History Matching
Authors: Hajizadeh Yasin , Christie Mike , Demyanov Vasily
Published: June 2009

This paper introduces a new stochastic approach for automatic history matching based on a continuous ant colony optimization algorithm. Ant colony optimization (ACO) is a multi-agent optimization algorithm inspired by the behaviour of real ants. ACO is able to solve difficult optimization problems in both discrete and continuous variables. In the ACO algorithm, each artificial ant in the colony searches for good models in different regions of parameter space and shares information about the quality of the models with other agents. This gradually guides the colony towards models that match the desired behaviour – in our case the production history of the reservoir. The use of ACO history-matching has been illustrated on a reservoir simulation case for Gulf of Mexico which showed that Ant Colony optimization can be used to generate multiple history-matched reservoir models.
Faster Convergence in Seismic History Matching by Efficient Parameter Searching
Authors: Sedighi F. , Stephen K. D.
Published: June 2009

Seismic history matching is the process of modifying a reservoir simulation model to reproduce the observed production data in addition to information gained through time-lapse (4D) seismic. The search for good predictions requires that many models are generated particularly if there is an interaction between the properties that we change and their effect on the misfit to observed data. In this paper we introduce a method of improving search efficiency by estimating such interactions and partitioning the set of unknowns into non-interacting subspaces. We use regression analysis to identify the sub-spaces which are then searched separately but simultaneously with an adapted version of the quasi-global stochastic neighbourhood algorithm. We have applied this approach to the Schiehallion field, located on the UK Continental Shelf. The field model, supplied by the operator, contains a large number of barriers that affect flow at different times during production and their transmissibilities are highly uncertain. We apply history matching by modifying the model. We find that we can successfully represent the misfit function as a second order polynomial dependent on changes in barrier transmissibility. Firstly, this enables us to identify the most important barriers and, secondly, we can modify their transmissibilities efficiently by searching sub-groups of the parameter space. Once the regression analysis has been performed we reduce the number of models required to find a good match by an order of magnitude. By using time-lapse seismic to effectively condition saturation and pressure changes in history matching we have gained a greater insight into reservoir behaviour and have been able to predict flow more accurately with an efficient inversion tool. We can now determine unswept areas and make better business decisions.
Optimum Logging Programs in Tight Sands
Authors: Tchambaz M.
Published: June 2009

High potential of tight sands (quartzitic sandstones) makes these non-conventional reservoirs a priority for oil companies during next decades. Due to numerous formation evaluation challenges in tight sands, conventional logging does not allow reliable and comprehensive investigations that are essential for exploration and development.

Classical logging techniques/measurements are frequently affected by significant uncertainties, leading sometimes to erroneous evaluation results.

New technology has brought advanced logging methods improving accuracy and reducing uncertainties of reservoir evaluation and characterization. Efficient implementation of these techniques is explained considering resolution/precision and limitations of measurement physics.

Best practices for logging in this type of formation are recommended with guide-lines and examples. Depending on well category (exploration, semi-exploration, appraisal or development), appropriate and optimum logging programs can be designed and sequentially performed to acquire full set of necessary data/information.

Latest generation of logging tools, in sonic, nuclear magnetic resonance, accelerator-neutron, formation-tester and analysis-sampling techniques, which offer significantly better evaluation, are proposed in integrated and optimized methodology. All of advanced logging tools may not be needed systematically for all types of wells; selective criteria are analyzed according to defined objectives/needs, reservoir particularities or/and sequential investigation results.

Data/information provided by tool answers-measurements are linked to key equations that will be accurately solved in different workflow implemented within the framework of formation evaluation, reserves estimation, completion selection, stimulation design and enhanced production projects.

This approach could be considered as guide lines for preparation of specific tool combinations and adequate logging programs fundamental for tight sands potential assessment and important management decisions.
An Improved Method for Total Mechanical Skin Calculation for Perforated Completions
Authors: Kabir Akim H. , Salmachi Alireza
Published: June 2009

Computation of total mechanical skin for perforated completions and comparison of various completion options is a challenge faced by Engineers involved in completion design/optimization. The topic of total mechanical skin calculation has been investigated by various authors. Karakas-Tariq (1991) proposed a method which is widely accepted by the industry for its simplicity, ease of use and a good theoretical basis. However, this method has a serious drawback in that it fails to give consistent, reasonable & continuous results if a parametric study is done on perforation length or invasion damage depth.

A review of Karakas-Tariq perforation and total mechanical skin model has been conducted and their shortcomings have been identified. The calculated total mechanical skin is discontinuous and illogical as the perforation length crosses the damage boundary (for a fixed damage depth) or as the damage boundary crosses the perforation tunnel tip (for a fixed perforation length). Various techniques have been tried to solve this problem. An ideal solution should honour the Karakas-Tariq model for perforation tunnels terminating some distance away from the damage boundary and should give reasonable and continuous results as the perforation tunnel reaches or extends beyond the damage boundary. The proposed solution, developed using analytical equations, achieves this desired outcome. Flow has been split between a stream which passes through the damaged zone and the stream which goes directly into the perforation tunnels. The resulting modified Karakas-Tariq method has been extensively scenario tested with synthetic & published well completion data and results are encouraging. This improved method now can be incorporated in any comprehensive perforation/inflow modeling software for comparing various completion options.
SubFace Matrix-Fracture Transfer Function: Improved Model of Gravity Drainage/ Imbibition
Authors: Abushaikha Ahmad S. A. , Gosselin Olivier R.
Published: June 2009

Gravity is a major recovery mechanism of naturally fractured reservoirs, where fracture gas drains matrix oil until equilibrium is reached with the capillary forces (wrt fluid densities, matrix gas capillary pressure and block height). The challenge of modelling gravity drainage in dual-medium simulation is to match the final maximum recovery, using integrated pseudo-capillary pressure curve, and the correct recovery kinetics. The paper suggests an approach to improve the simulation of the recovery kinetics in gravity drainage by dividing the matrix block for the fluid transfer function in two specific parts: saturation front part (SFP) and initial state part (ISP). As the invading gas enters the matrix the SFP and ISP areas increase and decrease respectively, until the final recovery is reached at equilibrium point. The contributions from each part are summed up to equal a mass conservation equation at each time step for each matrix cell. Properties of SFP depend on the invading fluid saturation and ISP hold the initial state properties, hence its name. This SubFace formulation can be implemented in flow simulator for reservoirs exhibiting a dual-medium behaviour.

Our SubFace Transfer Function approach (SF), performs well versus not only conventional transfer functions (Kazemi, Gilman), but also versus two improved ones: Quandalle-Sabathier, and Lu-Blunt (non-Warren-Root General Transfer Function) in matching the results of fine-grid single-medium models under various parameters (capillary pressure, matrix shape and mobility). We also tested SF in mixed-wet water-oil system to assess its capability of modelling gravity and capillary imbibition.

This new formulation improves dual-medium simulations of fractured reservoirs with an accurate representation of matrix-fracture exchanges, and better reserves assessment and reservoir management.
Reservoir Facies Modeling Using Intelligent Data Gathering in an Iranian Carbonate Field
Authors: Lakzaie A. , Ghasem-Alaskari M. K. , Vaziri S. M.
Published: June 2009

The construction of facies model is one of the most crucial undergone procedures of any stochastic geomodeling. It could be employed as a conditional data for any property simulation which results in a more reliable reservoir characterization in further steps.

A section of an Iranian gas reservoir with six wells was studied to determine the 3D reservoir facies model. Fifteen reservoir facies were first detected along one of the wells with detailed core and thin section descriptions. Due to the significant difference between the core and log data resolution, facies were clustered into four major groups regarding the digenetic processes and petrophyiscal lithofacies properties (permeability and porosity). The lithofacies specification effect on petrophysical properties distribution is usually the only criterion that is considered in conventional simulations. In this paper, however, the diagenetic processes which have a main influence on reservoir properties variation, especially permeability and porosity, have been considered in reservoir facies clustering.

After clustering process, using the available logs and with the help of the neural network, facies distributions along other five wells were also specified. To generate a 3D facies distribution into reservoir scale, SIS methodology was utilized with reference to the previously generated reservoir zonation from sequence stratighraphy, where Acoustic Impedance seismic attribute was set as the secondary data. This attribute was produced by model based inversion method applied in seismic cubes.

Since the diagenetic processes have highly influenced the rock properties of this carbonate reservoir, their effects have been considered as the most important parameter in reservoir facies determination. The ultimate model properly honored each expected sequence cycle properties such as diagenetic processes and lithofacies.
Modelling the Stability of Thin Water Films Using SEM Images
Authors: Frette Olav Inge , Virnovsky George , Hildebrand-Habel Tania
Published: June 2009

Understanding reservoir wettability–including wettability alteration mechanisms–is important to model and to optimise oil recovery. When oil enters an originally water wet porous rock under primary drainage, the oil will gradually displace the water in the pores and a thin water film will be left between the pore walls and the oil. Under certain conditions, the water film may become unstable and collapse. Depending on the chemistry of the oil, water, and porous rock, this collapse may result in wettability alteration. Stability of the water film will control the wettability alteration of the porous rock. Equilibrium saturation configurations in the oil-water system at primary drainage are simulated in 2D for a realistic pore space geometry obtained directly from high resolution scanning electron microscope images and thus retaining geometric features of the porous rock under consideration. The eventual collapse of the wetting phase film is controlled by the curvature of the surface and the disjoining pressure isotherm. Given the critical disjoining pressure value depending on the temperature and the chemical properties of the system at hand, the model facilitates computation of the "wettability index", i.e., the fraction of the rock surface which will come in direct contact with oil and hence potentially become oil wet. Both synthetic and realistic images are analysed. The generic studies show the influence of the surface roughness of the pore walls on the fraction of the surface which can potentially be converted to oil wet for different drainage pressures.
Model-Based Integration and Optimization – Gas Cycling Benchmark
Authors: Juell Aleksander , Whitson Curtis H. , Hoda Mohammad Faizul
Published: June 2009

A benchmark for computational integration of petroleum operations has been constructed. The benchmark consists of two gas-condensate reservoirs producing to a common process facility. A fraction of the processed gas is distributed between the two reservoirs for gas injection. Total project economics are calculated from the produced streams and process related costs. This benchmark may be used to compare different computational integration frameworks, and optimization strategies.

The methods of model integration and optimization discussed in this paper are applicable to complex petroleum operations where it is difficult to quantify cause-and-effect without comprehensive model-based integration. A framework for integration of models describing petroleum operations has been developed. An example test problem is described and studied in detail. Substantial gains in full-field development may be achieved by optimizing over the entire production system.

All models and data in the benchmark problem are made available so that different software platforms can study the effects of alternative integration methods and optimization solver strategy. The project itself can, and probably should, be extended by others to add more complexity (realism) to the reservoir, process, and economics modeling.
Application of the Monte Carlo Simulation in Calculating HC-Reserves
Authors: Komlosi Zsolt , Komlosi Julia
Published: June 2009

One of the key features of E&P companies is their proved reserves in hydrocarbon deposits. Reserve estimation requires knowledge of Initial Hydrocarbon in Place, technical reserves and economic conditions including annual cash flow estimation in the forecast period. Since all parameters used in evaluation procedure are burdened by rather more than less certainty. Therefore, in a sophisticated evaluation process, there should be determined not the expected values only (deterministic way), but errors/uncertainty of estimation as well (stochastic way) applying Monte Carlo simulation.

The estimation procedure comprises three main stages (the third stage /economic modeling/ is not discussed in this paper). In the first stage, key input data (e.g., area, thickness, porosity, and so on) are treated as statistical variables, and the result of the simulation is probability distribution function of HCIIP. This is an input of next stage.

In the second stage technical reserves (recoverable resources) should be estimated. There could be several assumptions for production procedure for a reservoir (as e.g., drive mechanism, hydrodynamic system, phase behavior of reservoir fluids, well spacing, water injection, presence of pressure barriers etc). Each regime (i.e. scenario) can be modeled applying input parameters as statistical variables. This method is named a multiscenario method in the literature. Simulation result for each scenario is a probability distribution function (PDF). While, expected value of PDF reconstructs the deterministic result and gives a basis for project evaluation, the "width" of PDF is proportional with uncertainty of the estimation. Estimating probability of each scenario a combined technical reserve PDF can be derived. Its first percentile can yield proved reserve for booking procedure after economic limit test.

Authors show some case histories how to apply method after a brief theoretical summary referring to SPE-PRMS accepted.
Mature Oil and Gas Assets: From Securing Resources to Maximising Reserves and Production
Authors: Ondracek Walter , Liebl Werner
Published: June 2009

Mature oil and gas fields have been prudently and successful operated since decades by asset teams securing booked reserves, preserving aging facilities and continuously improving performance indicators like costs per barrel or barrels per employee.

However, the operating mode has been rather conservative with respect to resources employed to increase production capacities and ultimate recovery.

Today, with peak oil as a realistic threat and the hectic quest for more oil and gas reserves, oil companies need to change their strategy. Expected high oil prices support such a change, and aging surface facilities force us to change fast.

The paper summarizes how we went about defining the basis for the required change in OMV/PETROM. It is about defining success criteria which go beyond technology and set the framework right for the implementation of sustainable field re-development projects to maximize capacities and recoveries.
Increasing the Capacity of an Underground Gas Storage by Optimized Well Completions, Matzen Field, Austria
Authors: Florian Thomas , Ueberer Wolfgang , Nederlof Eduard
Published: June 2009

This paper presents an overview of methods and technologies, OMV Austria has already implemented and plans to introduce in Underground Gas Storages (UGS) to improve the performance of single wells and thus to increase the total capacity of the UGS.

Since 1968, OMV Austria operates six UGS in the Matzen Field, located in Lower Austria near Vienna, and one UGS in Upper Austria.

The depths of these former sandstone gas reservoirs vary from 550 to 1,200 m. At the moment, the maximum working gas volumes (WGV) equals 2.33 billion m3. Withdrawal and injection is mainly achieved with 150 former gas production wells. Most of the existing wells are equipped with sand control completions. Well tests have shown that moderate to high skins are present. Nevertheless, withdrawal rates of about 15,000 m3/h per well can be achieved.

The increasing demand for gas initiated the necessity to improve the capacity of OMV's underground gas storage operations. Additionally, reservoir studies of all seven gas storage reservoirs indicated a potential for cost savings by reducing the number of active wells. Furthermore the reservoir models identified optimum well locations for infill drilling operations. In order to execute this strategy, the following measures have been worked out: Existing wells were converted to high-capacity wells by replacing Inside Casing Gravel Packs (ICGP) by Open-Hole Gravel Packs (OHGP)Drilling of two new high-capacity horizontal wells completed with an OHGP and Expandable Sand Screen (ESS).Increasing the maximum operating pressure in the underground gas storage reservoir

For two newly drilled wells, state of the art completions were chosen. By installing a horizontal open-hole gravel pack in one well, and an ESS in the other, rates of up to 50,000 m3/h/well can be reached. Re-placing old ICGP's by OHGP led to increased withdrawal rates of up to 35,000 m3/h per well.

For both, the re-completions and the new wells, a state of the art mud system (drill-in fluid and workover fluid, respectively) was used for the first time in gas reservoirs.

However, the most economical way to improve the capacity of underground gas storage is to increase the working gas volume. Currently the working gas volume is limited by the initial reservoir pressure (=maximum operating pressure). At the moment, OMV Austria is preparing a study to get the allowance for increasing the maximum operating pressure in two underground gas storages. This could add another 300 million m3 of working gas volume.
Injection of Supercritical CO2 into Deep Saline Carbonate Formations, Predictions from Geochemical Modeling
Authors: Taberner C. , Zhang G. , Cartwright L. , Xu T.
Published: June 2009

Modeling of supercritical CO2 injection into a deep saline aquifer from a carbonate formation (calcite and dolomite, with minor anhydrite) was performed using TOUGHREACT (Xu et al. 2006) with Pitzer ion-interaction model implementation for handling high salinity problems (Zhang et al. 2006). The formation brine salinity is ~225,000 ppm (NaCl dominant), temperature at 102°C and pressure at 225 bars. CO2 injection rate was considered constant for a period of 1 year through a horizontal well in a 3D model domain. The carbonate formation was assumed to have homogeneous porosity and permeability and to be overlaid by an impermeable seal. The effect of a higher permeability fault with orientation perpendicular to the horizontal well, and bounded by the impermeable overburden, was evaluated. The impact on mineralogical and rock property changes in the saline aquifer during injection has been assessed. The simulations found that: (1) the higher permeability fault acts as a CO2 conduit; (2) a dryout zone is developed within a few meters from the injection well due to displacement by supercritical CO2 and dissolution of water into CO2 stream (3) at the front of the dryout zone, brine is further concentrated due to water dissolution into CO2, pH is lowered from 5.5 to 3.1, halite (NaCl) and anhydrite (CaSO4) precipitate, and the brine becomes CaCl2–dominant; (4) near well-bore porosity reduces by ~5%-17% due to halite precipitation (dryout zone); (5) HCl gas is generated from the dryout front; (6) calcite and dolomite dissolve as the CO2 plume advances during injection; (7) anhydrite, however, slightly dissolves along the CO2 front, but precipitates in the area corresponding to the CO2 plume with higher proportions near well-bore. These findings are valuable for the assessment of injectivity changes and near well-bore stability of saline aquifers in carbonate formations during injection of CO2. The overall mineral trapping in hundreds of years is not the focuss of this paper. However, from ongoing modeling experiments, mineral trapping is anticipated to be not significant for the mineralogies and brine chemistries and salinities of the carbonate formation under assessment. This study method is useful for the further evaluation of engineering options to enhance immobile trapping of CO2 and mitigation measures for potential injectivity impairment.
Uncertainty Reduction By Production Data Assimilation Combining Gradual Deformation With Adaptive Response Surface Methodology
Authors: Busby Daniel , Feraille Mathieu , Gervais Veronique
Published: June 2009

We propose a workflow to reduce initial uncertainty of the reservoir model by incorporating production data. Advanced statistical methods such as sensitivity analysis, Gaussian process response surfaces, sequential experimental design and gradual deformation are combined to produce a very cost effective approach to production data assimilation. In previous works, response surface and experimental design methods have been proven quite effective for uncertainty propagation workflows; however they were only able to deal with continuous and discrete parameters. By using the gradual deformation method we are able to include stochastic parameters such as permeability and porosity, thus avoiding previous limitations. The advantages of using advanced non-parametric response surface methods are highlighted both in obtaining accurate global sensitivity indices and also to apply a full probabilistic inversion approach. Note that both methods generally require several thousands of model runs and are therefore unpractical without using response surface methods. Statistical diagnostics are used to validate the response surface models and adaptive sequential design strategies are proposed to improve their accuracy.

The workflow is applied to production data assimilation of a Brazilian oil field. In a first phase the production history mismatch is analyzed to understand the general behavior of the model as well as to select the uncertain parameters mostly responsible for this mismatch. To perform this phase experimental design and sensitivity analysis techniques are used. In a second phase another objective function is built using only data that seem to be possibly matched using the current model and set of parameters. The new objective function is used in a probabilistic inversion loop to obtain posterior distribution of parameters and to reduce the forecasting uncertainty. The results of the study can then be directly used to obtain reliable probabilistic forecasts. Moreover, posterior distributions of parameters can be utilized to reduce uncertainty ranges in a subsequent study with the updated geological model.
Real Time Integration of Reservoir Modeling and Formation Testing
Authors: Gisolf Adriaan , DUBOST Francois , ZUO Julian , WILLIAMS Stephen , KRISTOFFERSEN Julianne , ACHOUROV Vladislav , BISARAH Andrawiss , MULLINS Oliver C.
Published: June 2009

The increasing complexities of newly discovered reservoirs coupled with the increasing cost structure of field development mandate significantly improved and timely work flows for reservoir evaluation. Traditional modeling workflows are typically time consuming and require well organized cross disciplinary integration between geoscientists. Such models and processes are not well suited to be used and updated during formation evaluation acquisition phases of field development. In this paper a more accessible approach is proposed and demonstrated. The existing fluids model is combined with the current geologic model to construct an accurate representation of key features of the reservoir. This model is then used to predict data for a wireline formation sampling and testing tool (WFT), with emphasis on downhole fluid analysis (DFA). In this process, current reservoir understanding is tested by direct measurement in real time. If differences are uncovered between predicted and measured log data, the WFT tool is in the well, and measurements can be made to uncover the source of the error.

In this paper a workflow is demonstrated where WFT DFA and PVT lab reports were used to build a fluid model after the first exploration well data was acquired. This model was then used to predict fluid properties and WFT DFA logs for a subsequent well intersecting nominally the same compartment. These DFA predictions presumed fluid equilibrium and flow connectivity. Real-time comparisons were made of predicted and measured pressures, fluid gradients, contacts and DFA data obtained from the WFT logging run. Agreement of predicted and measured log data indicates that fluid properties and reservoir connectivities used for the modeling are correct. If predictions disagree with measurements the acquisition program can be altered in real time to ensure sufficient data is acquired to understand the reservoir model inaccuracies.

During the WFT logging job, this predictive model enabled validation of critical WFT data. This process also allowed testing of the reservoir connectivity. It was discovered that either compartmentalization or lateral disequilibrium of the fluids in the reservoir exists. Interpretation of the DFA data suggested that a subtle lateral disequilibrium exists and the assumption of reservoir connectivity is supported.
Comparison Between Smart And Conventional Wells Considering Uncertainties
Authors: da Silva João Paulo Q. G. , Schiozer Denis J.
Published: June 2009

The selection of a production strategy is one of the most important tasks to ensure success of petroleum fields development. In order to improve the performance of fields, the use of smart wells is becoming a common practice. In such wells, devices like valves and sensors are able to monitor and control the production, in real time, adding flexibility to the operation. However, it is possible that the expected gain of these wells production does not pay off the required additional investments. Thus, the aim of this research is to compare the differences between smart and conventional well performances.

A methodology of production strategy optimization, which considers the availability of different platforms, each one with a particular fluid treatment capacity, was developed and applied to both the conventional and smart wells. Special care was given to some details of the methodology in order to guarantee a fair comparison between the two options. The methodology was applied to a heterogeneous reservoir, considering a deterministic case. After it, the sensibility of the model was studied by changing geological characteristics, adding uncertainties to the problem.

The optimization results showed small differences between the two alternatives. Consequently, smart wells were able to improve oil production and reduce water production but the net present value (NPV) indicated that the use of conventional well was, in average, slightly more advantageous. Also, the application of different platforms with different capacities induced changes in the performance of the two kinds of wells. Finally, a sensitivity analysis and a detailed discussion were made in order to study situations where the smart wells could be applied.

With the developed methodology, it was possible to carry out a fair comparison between the smart and conventional wells, providing good confidence and efficiency in the optimization process.