bluuebunny/crossref_metadata_2025_split huggingface dataset:
Offshore Chemical EOR: The Role of an Innovative Laboratory Program in Managing Result Uncertainty to Ensure the Success of a Pilot Field Implementation
Authors: Zainal Suzalina , Manap Arif Azhan A. , Hamid Pauziyah A. , Othman Mohamad , Chong Mizan Omar , Yahaya A. Wafi , Darman Nasir , Sai Rithauddin M. 
Published: June 2014

Abstract
Ensuring a pilot project a success operationally, while gathering reliable data for a full-field implementation is critical. For this reason, various aspects of project planning and operational considerations need to be addressed. This include conceptual design, facilities and operational considerations, resources planning, integration of activities and most importantly, pilot objectives. However, all these planning will not be successful without a properly designed and executed laboratory test program. Such laboratory program will minimize result uncertainty and ensure the proposed pilot meet its objectives.
The first Chemical EOR (CEOR) pilot project in Malaysia involved an Alkaline-Surfactant injection utilizing high salinity injection water in a high temperature reservoir. It pioneered the Single Well Chemical Tracer (SWCT) method for EOR project evaluation in Malaysia. The main objective of the pilot is to assess the effectiveness of the Alkaline-Surfactant formulation to improve oil ultimate recovery through the reduction of residual oil saturation.
Being the first of its kind in Malaysia, an extensive laboratory program is required to ensure the injected alkaline-surfactant formulation performed at its most optimum and conclusive data is gathered. This data will be used as input to the future field development plan.
This paper presents a comprehensive laboratory test program covering pre-pilot, pilot and post-pilot laboratory analysis designed for offshore high salinity injection water and high temperature reservoir. It highlights the challenges imposed by offshore operation to design an optimum chemical solution considering that salinity and hardness of the water used to dissolve the chemicals are critical for an alkaline-surfactant system. It also discusses the continuous and controlled quality check process to validate the performance of the alkaline-surfactant solution. Finally, it presents the chemical adsorption study to evaluate chemical flood potential for the future full field CEOR implementation.
Modeling Fluid Flow in Deformable Fractured Reservoirs using Full Tensor Permeability
Authors: Bagheri M. , Settari A. 
Published: June 2014

Abstract
Several issues related to fluid flow in naturally fractured reservoirs are generally ignored or inadequately considered in ordinary reservoir simulation. These aspects include the variation of fracture permeability with stress and tensorial nature of the permeability field, either pre-existing or developed due to stress dependence. This study presents a methodology for taking into account these interrelated aspects of fluid flow and describes their implementation in a new advanced reservoir simulator. In order to capture all the interactions involved, a modular simulation system was developed consisting of a geomechanical model iteratively coupled with dual porosity reservoir simulator with the ability to handle variable full tensor permeability. The geomechanical solution uses the equivalent continuum approach, considering both rock and fracture deformation properties. The nonlinear stiffness of fractures varies with the effective stress according to a law typical for joints. The overall deformation is obtained considering the stress field and pore pressure provided from the flow module. The effects of the deformation of fractured media on fluid flow are rigorously captured using the decomposed deformation components of each media. Flow properties of each individual media (matrix and fractures) are then translated from their deformation components. Flow model then carries on with these new properties using a 27-point discretization technique of Multi Point Flux Approximation (MPFA).
Response Surface Methodology Approach for History Matching and Uncertainty Assessment of Reservoir Simulation Models
Authors: Slotte P. A. , Smørgrav E. 
Published: June 2014

Abstract
We present theory and application of a new approach for assisted history matching and uncertainty assessment. In a Bayesian framework the a priori geological information is conditioned to the production history to give the posterior probability distribution function (pdf). The full posterior pdf is explored to assess the uncertainty through ensembles of reservoir models sampled by a Markov chain Monte Carlo algorithm. To achieve this we construct proxy functions for the output of the flow simulator for all measurements that enter a global objective function. The proxy functions are constructed using polynomials and multi dimensional kriging. An iterative loop, in which ensembles of reservoir models are sampled from the posterior pdf, is run to improve the quality of the proxy functions.
The power of the application is demonstrated on two reservoir models. First we apply the method on a synthetic case. A modified reservoir simulation model from a small StatoilHydro operated oil field is investigated with a synthetic production history and 20 tuning parameters. Finally we apply the method to the StatoilHydro operated Heidrun field. A model which covers the upper formations of the field with 26 production wells, 11 injector wells, and 56 tuning parameters is conditioned to 11 years of production history. We show that it is possible to construct proxy functions accurate enough to describe the full posterior pdf and thereby assess the uncertainty associated with these reservoir models.
Modeling the Downhole Choking's Impacts on Well Flow Performance and Production Fluid Allocations of a Multiple-Zone Intelligent Well System
Authors: Sun Kai , Coull Craig , Constantine Jesse , Albrecht Kenneth , Tirado Ricardo 
Published: June 2014

Abstract
The intelligent well system (IWS) is normally operated with multiple-zone production/injection in the commingled condition, which makes it difficult to predict the effect of IWS operations on well flow performance and zonal deliverability. This is because: 1) The production string, downhole control equipment and isolation tools separate production fluids into different flow paths (tubular/annulus), and the different flow paths have different resistance to each zone's outflow; 2) the reservoir and fluid properties of individual zones are normally different, and these varying properties will cross-impact the outflow of each other's zones when fluids are commingled; 3) downhole choking operations will impact the wellbore pressure profile, thus impacting the production profile from each zone; and 4) Simulate the fluid temperature profile and the effect on pressure and flow profile for the IWS completion is a complex task. The current published works have not covered the whole spectrum.
To address this situation, an analysis tool has been developed, combining the developed comprehensive thermal model with integrated inflow performance relationship (IPR) technology and innovative operation point searching algorithm. For any downhole choking operation scenario, the flow allocations and profiles of wellbore pressure, temperature and fluid velocity can be predicted. This provides the operators insight into how to choke the downhole valves to meet the production enhancement target. It also gives an insight of how we customized the design of the downhole valve settings to achieve the production objectives. In addition, the threshold pressure at commingle point to control crossflow can be predicted through this technology, which provides potential ability to control/monitor possible crossflow of multiple-zone production through the intelligent well monitoring and control system. For demonstration purpose, a potential case study of a typical deep-water two-zone IWS was used for analysis. Model verifications were provided by comparison with the third-party software. Analysis and comments of the comparison have been provided.
Deriving Matrix Properties, Fluid Types and Saturation from RST-CHFR Combination in Siegenian Reservoir of Bir Berkine Field, Algeria
Authors: Okuku Chris , Abdellatif Zanoun , Ali Hamoudi , Noureddine Kanit , Mokrani Nabil 
Published: June 2014

Abstract
Drilling under severe borehole instability conditions can result in the well being side tracked or worse, abandoned. In some cases, casing can be run quickly, but this leaves the well completed without the opportunity to acquire the essential openhole suite of logs for quantitative formation evaluation. In the absence of openhole data, the use of Analysis Behind Casing (ABC) suite of tools such as the Reservoir Saturation Tool (RST) and the Cased Hole Formation Resistivity Tool (CHFR) allows rock matrix properties, fluid type and saturation to be derived.
This approach was implemented in the Siegenian formation for a well in Bir-Berkine Field. Casing restriction of 4.5" limited the option of the ABC logging suite to only RST-C (111/16") and CHFR (33/8"). The RST was used mainly for acquiring data for formation matrix estimation, porosity and oil saturation through the inelastic and Sigma acquisition modes. Moreover, the CHFR tool was used to obtain the resistivity of the formation. Offset wells information was used for the calibration of the cased hole data.
Three independent saturations were derived from the Inelastic, Sigma and CHFR measurements. Comprehensive comparison and integration of those results were carried out.
Quantitative formation properties like clay, calcite and quartz volumes combined with porosity and water saturation were estimated. The three independent estimated saturations indicated that the zone of interest was a potential oil bearing formation. The reservoir was perforated resulting in good oil recovery.
Integration of ABC logs in contingency situations like this one provides a successful alternative to quantitative formation evaluation with openhole logs.
Immiscible Gas Injection: Challenges, Example of the 16th TH Horizon, Austria
Authors: Gruenwalder Markus , Clemens Torsten 
Published: June 2014

Abstract
The 16th TH horizon is a mature oil reservoir located about 20 km east of Vienna. Screening of the reservoir and EOR technologies revealed that from one of the reservoir compartments incremental oil might be produced by gas injection.
In 2007, injection of various gases into this reservoir compartment (OOIP 86 MMstb) was investigated. An EOS model was created and slim tube experiments were performed. The results of the slim tube experiments indicated that neither CO2, CH4 or N2 are miscible with the 24.8 API oil under reservoir conditions of 120 bars and 60 degrees centigrade.
Injection of CO2, CH4 and N2 was investigated using a sector and full-field model. The results show that incremental recovery compared to the base case is only about 1.5%. Owing to the oil viscosity 5.5 cP, the gas viscosity 0.02 cP, the oil density 855 kg/m3, the CO2 density 290 kg/m3 and the reservoir thickness of 30 m, severe gas override occurs in the reservoir. The small dip of the reservoir of 2-4 degrees and high in-situ oil viscosity lead to a small gravity drainage rate, hence the incremental recovery is limited.
At a first glance, the project could be economically attractive though. The field is located close to Vienna where some pure CO2 is emitted. The CO2 emitted could be injected to reduce greenhouse gas emissions and generate emission trading certificates.
However, in the course of the study, it was seen that significant acceleration potential exists in this horizon. Accelerating oil production leads to faster perforation of the wells upwards towards top structure. Combining gas injection with acceleration of oil production reduces the incremental oil production by this technology. The reason is early gas breakthrough in the production wells perforated at the top of the formation due to gas override.
Optimization of Well Placement Using Evolutionary Algorithms
Authors: Ding D. Y. 
Published: June 2014

Abstract
Non-conventional wells allow to increase considerably hydrocarbon recovery. By considering the high drilling cost and the potential earn in well productivity, optimum implementation of non-conventional wells is an important issue in petroleum industry.
Considering large number of parameters involved in well placement and high reservoir heterogeneities, stochastic methods such as evolutionary algorithms are the most efficient approaches for optimization. In this paper, we present the CMAES (Covariance Matrix Adaptation - Evolution Strategy) method, which is based on evolutionary approach and has been considered as one of the best stochastic optimization method for non-linear problem. The application of CMAES to the problem of well placement optimization is presented. CMAES is an alternative approach for the well placement, and it gives comparable results with respect to the genetic algorithm.
Although the evolutionary methods such as CMAES or genetic algorithm are suitable for the modelling of well placement, their efficiency depends on various parameters involved in the model. In this paper, the impacts of model parameters in the optimization of well placement are also discussed.
Fluid Flow Simulations on Core Samples Containing Natural Fractures and Stylolites
Authors: Basquet Rémy , Rennan Lars , Ringen Jon Knut , Wennberg Ole Petter 
Published: June 2014

Abstract
This study aimed to understand the impact of natural open fractures and stylolites on flow in a porous sandstone reservoir by analysing fluid flow behaviour at small scale (core sample). This analysis was done both experimentally and with fluid flow simulations within full core samples.
Two core samples (seal peels) from the Snøhvit field in the SW Barents Sea were selected. These contain natural open fractures mostly associated with stylolites. Since no test data exist from the intervals with highest fracture intensity, it remained uncertain whether these fractures will affect the flow in the reservoir. Two series of flooding experiments were conducted on these core samples, one by tracer injection and the other by injecting gas (Nitrogen) in the 100% brine saturated seal peels.
Computed tomography (CT) scans were used to image the fracture/stylolites system, to monitor the flooding experiments and to build a consistent simulation model.
Single and two phase flow simulations were performed to mimic the experiments. First, the fractures and stylolites effective properties were determined via tracer injection experiments by matching the tracer production profile. Then, to simulate the gas injection, relative permeability and capillary pressure (Kr-Pc) curves generated from special core analysis (SCAL) measurements were applied for the matrix medium. For the stylolites, the same Kr curve was used and modified Pc applied. For the fractures, a linear Kr curve and no Pc were used. As a result, a good quality match was obtained, giving an understanding of the influence of a fracture/stylolites system on the flow within porous sandstone.
Next-Generation Sand Screen Enables Drill-In Sandface Completions
Authors: Coronado Martin P. , Pickle Brad R. , O'Malley Edward J. , Patel Paresh 
Published: June 2014

Abstract
Following successful field applications of solid-liner drill-in systems, efforts now focus on drill-in sand screen liners. This paper will discuss enabling technologies to meet the peculiar challenges of drill-in sand screen liners.
The screen liner must contain pressure when drilling to allow circulation through the bit and wellbore inflow during production. The screen's filtration media must also be protected from possible plugging during drilling. Rotating the screen liner to allow circulation may damage screens, so a drilling motor at the bottom of the liner drives the bit. Conveying fluid to the motor using a conventional inner circulating string may add sufficient weight to significantly limit horizontal and highly deviated well angles.
This paper addresses a technology that temporarily blocks flow through the screens during drilling to allow a pressure-tight circulation path through the liner to the motor without the need for an inner circulation string. Once drilling is complete and the liner is in place, the screen joints are simultaneously opened using hydraulic pressure applied within the liner, and the well is ready to be put on production. Temporarily closing off of the screen joints also has additional applications, such as simultaneously setting hydraulically-set open-hole packers without an inner circulating string.
The paper also discusses a time- and temperature-sensitive protective film applied to the screens during fabrication to prevent fluid egress into the filtration media until the film dissolves. Sufficient time for dissolution is designed into the film to allow the liner to be drilled into place while protecting the screen's filtration media from possible plugging during drilling.
Testing and applications of these technologies are discussed, along with economic advantages resulting from savings in rig time and improved success rates for properly placing screen liners. Operational aspects associated with this new system are outlined with regard to system components and job design.
Over 100 Conformance Fracturing Operations in Brazil: Results and Improvements
Authors: De Melo Ricardo C. B. , Aboud Ricardo S. 
Published: June 2014

Abstract
Many of the mature oil fields in the world produce commingled water. Water production increases the lift cost of a barrel of oil, as it needs surface handling when it is to be disposed, re-injected into other wells, or used for a different purpose.
Several techniques and chemistries have evolved over the past decades to address reduction of unwanted produced water. These different approaches to minimize water production are grouped under the name of water conformance. Selecting the proper water conformance method for a well depends on the correct understanding of the reservoir. Economics remains the main decision driver as to which technique and chemistry to use.
A quite effective technique among the different water conformance methods is conformance fracturing, a combination of hydraulic fracturing and water control. Among several operating companies, hydraulic fracturing still is the preferred technology to increase well productivity. The development of a family of lightweight proppants for hydraulic fracturing has allowed a more uniform fracture height and width, due to a lesser degree of proppant settling inside the fracture, resulting in a better connectivity with the wellbore and lower chance of breaching nearby water zones. On the other hand, chemistry of relative permeability modifiers (RPM) has been greatly improved over the past decade, and one can observe longer life on water control treatments done using RPMs.
In Brazil, we have conducted over 100 conformance fracturing operations to date, using conventional as well as lightweight proppants, and relative permeability modifiers, to meet the different targets they were deployed for.
This paper will summarize these treatments (design, logistics, materials, equipment), with obtained results (oil and water production over time), showing the improvements made over time.
Optimized Recovery from the Fram Øst Development through Extreme Well Design
Authors: Thorsen Arve K. , Gravem Trond , Manseth Arvid , Klausen Trond Skei , Øvrebø Torbjørn 
Published: June 2014

Abstract
Field development in mature areas of the Norwegian Continental Shelf (NCS) is changing from giant fields to minor localized hydrocarbon traps often made up of isolated and rotated fault blocks. The existing infrastructure needs to be utilized to make the additional reserves economic. Being a marginal part of a mature area, the existing subsurface and reservoir information is very limited.
The cost involved in field developments on the NCS is substantial and additional appraisal wells are often too costly, delaying the field development and increasing total cost. The solution to gain the information needed and to place the well optimally within the reservoir, is to have enough flexibility in the well design to evaluate and change the planned well trajectory based on the information acquired during drilling. The well trajectories in these cases are horizontal producers with normally one main bore in each fault block.
This case describes the application of precise 3D Rotary Steerable System and LWD measurements which enable accurate identification of the Oil-Water-Contact, Gas-Oil-Contact and top reservoir, for a horizontal well through multiple branches drilled from one main bore in a single continuous operation. The valuable information, obtained through controlled sidestep exploration drilling, provides additional knowledge to optimize the producing main bore. Horizontal wellbore placement is supported by real-time reservoir characterization through real-time formation pressure measurement to validate any fluid movements and fluid compartmentalization of the reservoir. Being able to perform this in a single run accentuates the unique effectiveness and flexibility available in the well construction process.
In this marginal field development in the North Sea realtime data acquisition and accurate well placement play a significant part in the success of the field development and illustrates to what extent precise 3D RSS and answers from LWD data help in effectively optimizing well placement and reservoir characterization.
Finite Element Modelling of Casing in Gas Hydrate Bearing Sediments
Authors: Salehabadi Manoochehr , Jin Min , Yang Jinhai , Haghighi Hooman , Ahmed Rehan , Tohidi Bahman 
Published: June 2014

Abstract
Casing integrity in shallow marine sediments could be challenging if natural gas hydrates exist in the sediments. Elevated wellbore temperature during drilling of deeper sections of deep offshore wells can cause in-situ gas hydrates to dissociate, thereby increasing pore pressure and altering the mechanical properties of the sediments. Gas hydrate can also dissociate during setting and/or cementing, causing gas release which could result in delaying completion of the wellbore due to the flow of gas around the casing (conductor pipe) or affecting the casing integrity or casing stability by creating voids (channels) in the cement sheath leading to non-uniform stress loadings.
In this communication, a numerical model is developed using a finite-element code to simulate the stability of casing in gas hydrate bearing sediments by considering the interaction between the formation, the casing, and the cement with coupling the thermodynamic stability of the hydrates to hydraulic, mechanical and heat transfer terms. The mechanical and hydraulic terms are fully coupled and the coupling between mechanical and thermal terms is modelled through staggered technique (one-way coupling).
To model the worst-case scenario, the permeability of gas hydrate bearing sediments is assumed very low as a result the gas and water generated during gas hydrate dissociation cannot flow and will increase pore pressure. The mechanical property degradation of formation due to hydrate dissociation is represented in the model by cohesion softening as a function of dissociated gas hydrate saturation.
The developed numerical model is found to be very useful in understanding the behaviour of wellbores drilled in gas hydrate bearing sediments, which will help the determination of the resultant stress fields and enable a more accurate determination of the required casing strength.