bluuebunny/crossref_metadata_2025 huggingface dataset:
A New Automated Algorithm for Designing the Optimal Single-Well-Chemical-Tracer SWCT Tests At Various Reservoir Conditions
Authors: Khaledialidusti Rasoul , Kleppe Jon
Published: September 2016

Single-well-chemical-tracer (SWCT) is the most commonly used field method to determine oil or water saturation in one-spot pilot. The SWCT method overcomes the limitations of the well-to-well tracer method, being long measuring time and excessive tracer dispersion. However, other limitations are encountered such as the shorter investigation region and the effect of the product acid due to the hydrolysis reaction on the reliability of the saturation measurement. The latter one is still considered to be a controversial issue.

Saturation measurements from large investigation regions are more reliable because of larger measured volume and longer distance away from the wellbore damage and capillary desaturated zone. However, some criteria prevent the test from reaching the desired investigation region and may thus cause deviations in the test results from the ideal test. These criteria are the higher fraction of hydrolyzed ester and the detection limit of ester, hydrolysis reaction during injection and production times, and fluid drift and tracer dispersion during shut-in time. The main objective of this research is to develop an automated algorithm to design the optimal SWCT test including the larger investigation region and more ideal tracer profile according to the reservoir conditions.

The devised algorithm has been programmed based on the six different stages. In the first four stages, all test design parameters in different investigation regions and retardation factors are calculated. The test design parameters are sizing the test volume, test timing (i.e., injection, shut-in, and production), tracer concentration during the test, and the mean residence volume. In the fifth stage, all criteria are taken into consideration to find the optimal test design. After that, the achieved parameters are applied in the simulation stage (sixth stage) of the workflow. The objective of the final stage is the investigation of the effect of the following items on the tracer result in order to develop more ideal (i.e., Gaussian) tracer profiles: 1) ester bank and concentration, 2) ester properties, 3) shut-in time and adapting the conventional rule to the reservoir conditions.

To evaluate the workflow methodology, two different field test cases with different reservoir conditions are employed in order to reflect the influence of different stages of the algorithm. After the numerical interpretation of these two tests, the algorithm is performed to design the optimal test with all criteria taken into account. The results show that the proficiency of the algorithm could be noticeable in the design of an optimal test with larger investigation region yielding more Gaussian-like profiles by the means of modifying the conventional rule of the shut-in time and selecting an optimal ester bank and concentration fitting to the reservoir conditions.
Maximizing Well Uptime Through Effective Well Operations And Integrity In South Iraq
Authors: Kumar Randhir , Hindawi Kareem , Awobadejo Mayowa , Alharthy Said , Al Jumah Ali
Published: September 2016

Achieving high production system availability of any asset is one of the most important target thereby creating a stable plateau production and continuous hydrocarbon supply to customers. This ambition can be reality with comprehensive planning & execution, and certain due considerations that enable integration across all the asset's divisions and units. The authors through this this paper deliberate on the most critical factors that can improve the uptime remarkably which contributed to the success story of the Shell operated asset in Iraq in achieving high uptime percentage of 99% in 2015. These factors are described in a level of detail in this paper.

Shell Operational Excellence Blades is a set of documents, containing rules and minimum requirements of operations in all the sub divisions of the asset, they show clear examples of best in class practices and the ways to implement them. These are followed by all the assets operated by Shell to ensure integration across the board and proper management of the asset, ultimately resulting in good outcomes.

Effective well operations describe the process for safely and efficiently operating wells within the integrity envelope to produce at their optimum. It is a key part of the operating integrity work stream and ensures wells are operated within Shell's Asset Integrity - Process Safety Management Standards (AI-PSM). It involves knowing and understanding the well operating limits, continuously monitoring and controlling the wells within these boundaries. Optimizing production through maximizing uptime is administered through a systematic daily well surveillance and optimization process, ensuring standards and processes are adhered to.

Production system optimization can be described as the loop of identifying a bottle neck, then removing it, allowing for increased production rates, which serves as a key point in realizing high uptime for any producing asset. Integrated planning on the other hand, supplemented by proactive surveillance, is another critical item that needs care and attention throughout the year. Surveillance is recommended to always by "proactive" and not "reactive," to prevent any possible system down time or irreversible damage.

All the assets are operated by people, and hence people integration comes forward as the glue that brings everything together and removes artificial boundaries, facilitating work delivery and improving the outcomes. Hence, implementing a collaborative working environment is highly encouraged.
Impact of Local Stress Heterogeneity on Fracture Initiation in Unconventional Reservoirs: A Case Study from Saudi Arabia
Authors: Oparin Maksim , Sadykov Almaz , Khan Safdar , Tineo Roberto
Published: September 2016

Drilling horizontal wells with subsequent multi-stage hydraulic fracturing have become essential for economic production of oil and gas from unconventional resource plays. The selection of appropriate intervals for perforation clusters (in cased holes) is one of the keys for a successful fracturing job in horizontal wells. An inappropriate interval may lead to extremely high breakdown pressures, or even an inability to breakdown, which can prevent that part of the well from contributing to the production.

Wellbore staging where perforation intervals are selected is based on minimum horizontal stress along the lateral has proven to be effective and has increased production contribution of each stage. We found this approach can be effective only in normal stress regime. In other stress regimes, e.g., strike-slip and reverse stress regimes, breakdown pressures were discovered to be higher in intervals of lower horizontal stress, contrary to what we typically see in normal stress regime.

This study adds practical soundness to theoretical methodologies of fracture breakdown pressure prediction, and improves the completion design to meet the expected fracturing pressure in the tectonically stressed environment of unconventional gas wells in Saudi Arabia.

To design completions that can withstand breakdown pressures in various stress regimes, hoop stress and the resultant fracture breakdown pressure must be taken into account. This study reviews the process of openhole image log analysis, selection of the uniaxial compressive strength (UCS) correlation, estimation of maximum horizontal stress and obtaining hoop stress. It collects and analyzes fracture breakdown pressures observed in unconventional gas wells. Various geomechanical aspects that influence breakdown pressure are investigated and compared with the actual breakdown pressures observed.
Towards a Robust Estimation of Permeability by Integrating Logging Data from Nuclear Magnetic Resonance, Acoustic, and Formation Tester
Authors: Thern Holger , Hinze Iris , Mohnke Oliver , Salazar Jesus , Kriegshaeuser Berthold
Published: September 2016

Permeability is critical for determining the producibility of hydrocarbon reservoirs. Permeability, however, cannot be measured directly by logging tools, but rather needs to be deduced from available logging data. We present a method to derive a continuous permeability profile from nuclear magnetic resonance (NMR) and acoustic (AC) logging data by incorporating formation tester (FT) mobility. The underlying theory and workflow are described and field data examples that validate the approach are discussed.

NMR permeability models combine porosity and an average pore size estimated from relaxation time measurements. Stoneley waves from acoustic logging deliver a permeability log by capturing the fluid particle motion between the borehole and the near borehole formation. Formation tester tools measure multiple formation properties including mobility, which is converted to permeability by multiplication with fluid viscosity. While NMR and AC data deliver a continuous, but uncalibrated permeability profile, FT mobilities are only taken at discrete depths with potentially large spacing.

We have developed a robust workflow to generate a continuous and calibrated permeability log from NMR and acoustic data, by incorporating formation tester mobilities. The workflow can incorporate wireline and logging while drilling (LWD) data and can be applied to clastics and carbonate reservoirs. In particular, carbonates can exhibit complex pore geometries due to diagenetic alteration that can make permeability assessment difficult. Permeability in clastic formations, on the other hand, can be affected by the presence of clays or by cementation. We have observed that incorporating formation tester data can contribute significantly to deliver a calibrated, continuous permeability profile from NMR and Stoneley waves.

We demonstrate the efficiency of our methodology by applying it to three field data examples from offshore carbonate formations. These examples demonstrate the value of integrating formation test mobility with NMR and, if available, acoustic permeability, to improve the petrophysical characterization of reservoirs. Advantages and limitations of the combination of all three measurement types are illustrated, and applications, such as the identification of pore geometry effects, are discussed.
The Importance of Implementing Petropysically Meaningful 3D Anisotropic Velocity Models to Improve the Interpretative Value of Microseismic Data
Authors: Taylor Scott , King Jeremy , Schaeffer Ben , McGreaham Lucas , Ghuneim Khaled , Hibbitts Todd
Published: September 2016

The issue of how much seismic rock properties change during a frac is not well understood. For years, most downhole microseismic monitoring operators have changed their velocity models for each stage. With advances in velocity analysis technology, this practice is under increasing scrutiny. The authors present a study of a West Texas microseismic dataset, in which varying levels of anisotropy are measured through tomography. Results demonstrate that higher orders of anisotropy have not only increased accuracy and aided in the development of a geologically relevant velocity volume, but also enhanced the interpretative value of the microseismic data. The 3D time-invariant model demonstrates more viable event locations and agreement with sonic log and borehole seismic (VSP) data. Furthermore, meaningful rock property estimates can be extracted from perforation data which not only adds credibility to the time invariant modelling approach but also adds significant information value."

The authors seek to extract more value from microseismic in order to make this measurement viable both in the current price environment and across a broader spectrum of wells. This is the first in a series of papers that will walk through the premise, basic steps and benefits to honoring an increasingly more sophisticated level of physics when building velocity models.
Joule-Thomson Coefficients from Well Test Analysis Data
Authors: Meisingset Knut Kristian , Pedersen Karen Schou
Published: September 2016

The paper describes how the reservoir temperature can be simulated from well test data. The procedure is exemplified using data for four different reservoir fluids, one gas condensate, one oil mixture, and two volatile oils. The reservoir pressures vary from 150 to 800 bar and the reservoir temperatures are in the range of 70 - 130oC. The procedure requires knowledge of the reservoir pressure and it is a further requirement that well test pressure and temperature data at bottom-hole conditions exists for a fixed flow rate and a period long enough to have a negligible heat exchange with the surroundings. The well test data reveals that the temperature of the gas condensate will decrease when expanded in the near well bore area, while a temperature increase is seen for the oil mixtures. With negligible heat exchange between the flowing fluid and the surroundings, the flow process can be regarded an adiabatic expansion of the reservoir fluid from reservoir to bottom-hole conditions. The enthalpy at reservoir conditions is found from a Pressure-Temperature flash at bottom-hole conditions corrected for a possible height difference between bottom-hole and perforation interval. The reservoir temperature is found from a subsequent Pressure-Enthalpy calculation at reservoir pressure. The thermal calculations are carried out using a cubic equation of state. The simulated reservoir temperatures are in good agreement with the data material.
Rock Typing Classification and Hydraulic Flow Units Definition of One of the Most Prolific Carbonate Reservoir in the Onshore Abu Dhabi
Authors: Alhashmi N. F. , Torres K. , Faisal M. , Cornejo V. Segura , Bethapudi B. P. , Mansur S. , Al-Rawahi A. S.
Published: September 2016

Defining the flow and distribution of fluids in porous media has always been of key importance in modeling and predicting the performance of oil and gas reservoirs. Based upon the rock-fluid interactions, reservoir rocks have to be classified into separate flow units called rock types. This task is particularly complex in carbonates as they are generally impacted by diagenesis and cannot be represented by a single porosity permeability relationship per litho-facie.

Establishing accurate rock types in carbonates, therefore, requires integration of various petrophysical data with the available rock, fluid and geological information. Various techniques have evolved in the industry for formulating rock-types (Pittman, RQI, FZI, Lucia, Winland, etc.), each technique offering its benefit depending on the nature and variety of data available.

This paper presents a newly adopted workflow to formulate an RRT definition for a carbonate reservoir by integrating data from MICP, CCA, petrophysical logs and lithofacies information. The workflow involves associating the pore throat size distribution evaluated using MICP data with the measured porosity and permeability values utilizing the Winland R35 equation. Hydraulic flow units are identified using the Stratigraphic Lorenz Plot, based on the change of flow and storage capacity slopes. Pc, PTR, Phi and K discriminators were established and were used to as cut-offs for defining intervals representing good and poor facies.

The new methodology helped to achieve a very good match (>80%) of water saturation from the initialized model with the log derived saturations in all wells drilled thus far in Reservoir-A. The methodology further helped optimize the number of effective rock types required to effectively delineate the field dynamic characteristics, helping reduce run time and anticipated convergence issues.
An Improved Methodology for Simulating Oil Recovery by Carbonated Water Injection: Impact of Compositional Changes
Authors: Al Mesmari Ali , Mahzari Pedram , Sohrabi Mehran
Published: September 2016

Enhanced Oil Recovery by carbonated water injection (CWI) has recently attracted significant attention. The main advantage of CWI, compared to conventional CO2 flood, is that it requires small amount of CO2 and it can be readily applied to oil fields with on-going or planned waterflood. The challenge with CWI is numerical simulation of the complex compositional changes that take place as a consequence of the transfer of CO2 from CO2-enriched (carbonated) water to crude oil under reservoir conditions. We have recently reported that these compositional changes result in the formation of a new gaseous phase within the oil and become the dominant mechanism controlling the performance of CWI.

In this investigation, utilising the results of novel direct visualisation experiments, a new and improved methodology for simulating the performance of CWI has been successfully developed that is capable of reproducing the physical processes observed in our micromodel and coreflood experiments. First, the parameters controlling the phase behaviour of crude oil and carbonated water were identified and an equation-of-state (EOS) was tuned to simulate the partitioning of CO2 between the aqueous phase and the crude oil. Furthermore, to properly account for the formation of the new phase during CWI, three-phase flow functions and kr were utilised for simulation of flow. Using an integrated automatic-history matching algorithm, the proposed methodology is then employed to examine the capability of commercial reservoir simulators to couple mass transfer and multi-phase flow during CWI. For this, the results of a series of consistent coreflood experiments were used where carbonated water was injected in secondary and tertiary modes.

The results of the history-matching exercises demonstrated that, to properly capture the underlying mechanisms of EOR by CWI, the phase behaviour and three-phase flow functions should be coupled in numerical simulation of the process. The results also revealed that the binary interaction coefficients between oil components and CO2 would control the extent of the gaseous-phase formation. Also, a relatively high value for critical gas saturation was obtained to history match the coreflood experiments, which was in agreement with the results of the direct visualisations experiments. Moreover, a variety of three-phase oil relative permeability functions were considered to replicate the movement of the gaseous-phase, which would be dictated by reconnection of the oil ganglia. The new phase formation outperforms other oil recovery mechanisms such as reduction of oil viscosity and oil swelling.

The results of the study help improve the accuracy of the numerical simulation of the oil recovery processes involving CO2 and carbonated water injection. This will in turn improve the quality of our reservoir performance predictions and the reliability of our economic calculations of these enhanced oil recovery techniques.
Visualizing Portfolio Tradeoffs With Perceptually Accurate Self-Organizing Maps
Authors: Kostuik K. , Mu Y. , El-Beltagy M. , Naiem A.
Published: September 2016

Multi-objective optimization and unsupervised machine learning were used to visualize relationships between portfolio composition and business performance tradeoffs. A multi­objective global optimization algorithm reduced the exponentially large space of possible portfolio outcomes to a set of Pareto optimal tradeoff frontiers for various combinations of decision and outcome constraints. The high-dimensional decision space was then reduced with an unsupervised neural network to generate Kohonen self-organizing maps (SOMs) for each tradeoff frontier. The resulting decision SOMs were rendered with a perceptually accurate color map and interactively linked with the tradeoff frontiers to enable visual data mining.

The interactive visualization revealed relationships between planning decisions and business outcomes in the complex and high-dimensional decision space. The interactive SOM automatically classifies similar strategies together and shows how neighboring strategies relate to each other. The analysis demonstrated that the proximity of portfolios on the tradeoff frontier does not imply similarity of underlying portfolio decisions, and that the mapping between decisions and outcomes becomes more complex with stricter constraints.
A Practical Workflow for Probabilistic History Matching and Forecast Uncertainty Quantification: Application to a Deepwater West Africa Reservoir
Authors: Yeh T. , Uvieghara T. , Jennings J. W. , Chen C. , Alpak F. O. , Tendo F.
Published: September 2016

Reliable reservoir uncertainty estimation is crucial to understanding its valuation and making robust decisions. Conventional practices where history matching and production forecast are performed on selected high-mid-low cases do not provide a reliable estimation of forecast uncertainty. This is typically reflected in a narrow range for ultimate recovery (UR) or net present value (NPV) predictions. In order to capture the inherent subsurface uncertainty, it is necessary to use an ensemble of models which spans the full uncertainty space.

The Probabilistic History Matching (PHM) workflow is an ensemble-based workflow, aimed to improve forecasting uncertainty estimation. One of the biggest challenges is that it typically requires a large ensemble size to span the uncertainty space due to the limited information (e.g. core data or well logs). This requirement may render the Assisted History Matching (AHM) exercise infeasible when computational resources are relatively limited. Therefore, it is necessary to reduce the number of models to a manageable size prior to performing AHM. Here we implement the Dynamic Fingerprinting workflow, to effectively select a set of representative models from the ensemble while preserving the uncertainty of the variables of interest. In this methodology, time-of-flight (TOF) and drainage time (DRT) information, which are direct estimates of swept and undrained volumes are used to characterize each model. A small subset of models is then selected based on their dissimilarity in flow pattern and used for AHM/forecasting.

The workflow was applied to a deepwater West Africa reservoir. An ensemble of 810 models was generated to represent the subsurface uncertainty. Ten models which were highly dissimilar in flow response were selected from the ensemble for AHM and estimating forecast uncertainties. The AHM was performed using an Experiment Design (ED) - Response Surface Modeling (RSM) - Markov-Chain Monte-Carlo (MCMC) workflow. For validation purposes, a different AHM workflow was performed on each of the 810 models using a derivative-free optimization algorithm. The comparison between the results supports the choice of the representatives from the Dynamic Fingerprinting work flow as well as the history matching conclusions from the ED-RSM-MCMC workflow.
Fast 2D Inversion for Enhanced Real-Time Reservoir Mapping While Drilling
Authors: Thiel Michael , Dupuis Christophe , Omeragic Dzevat
Published: September 2016

The new reservoir mapping-while-drilling technology provides enough data so that a real-time reservoir map can be created through inversion for a layered medium. These reservoir maps are used to optimize well placement and to improve reservoir understanding. Complex reservoirs can be imaged, but the assumption of a layered medium loses its validity when the reservoir cannot be approximated using 1D model locally, i.e., when the reservoir structure varies on the scale of the tool spacing. To improve reservoir mapping performance in such scenarios, an unbiased approximate 2D inversion is introduced that minimizes the error to the layer medium approximation of the reservoir. It is suited for any mildly 2D scenario in which the reservoir does not change abruptly. The method is validated on synthetic and field datasets.
Industrial Waste Injection Feasibility in North Dakota
Authors: Mohamed I. M. , Block G. , Abou-Sayed O. , Abou-Sayed A. S.
Published: September 2016

Class I and Class II waste re-injection are the most important methods for disposing of fluid in North Dakota: in 2007, more than 96% of produced water were disposed of using underground injection, and by 2012 all produced water was being managed by underground injection. While Class II injection covers waste produced from most Exploration & Production (E&P) activities, Class I injection wells are used for disposing of a special class of industrial wastes, including waste generated by petroleum refining, metal production, chemical production, pharmaceutical production, commercial disposal, and food production. Non-hazardous industrial waste and Naturally Occurring Radioactive Materials (NORM) not associated with E&P can also be injected using Class I wells. In all cases, the primary concern for permitting and safe operations is to (1) predict the movement of the injected waste to ensure that it stays within pre-defined formations, and (2) ensure that pore-pressure increases caused by injection do not impact neighboring offset wells.

Results from a geochemical study of the feasibility of disposal into the Dakota Sands (Inyan Kara formation) in North Dakota will be presented. Analyses were made using a compositional reservoir simulation (REVEAL) to predict the pore-pressure distribution, direction and movement of the injected fluid, as well as chemical reactions between formation brine/waste/formation rocks and the effect of these chemical reactions on formation injectivity and cap rock integrity. Forecasts indicate that over 50 years of injection the injected wastes will be completely trapped within the Dakota Sands (no fluid flow is expected to penetrate through the cap rock) and injection pressures are expected to remain well below the estimated fracture pressure. While the Inyan Kara formation is therefore a reasonable storage trap for industrial wastes, carbonate and sulfate scales may cause near wellbore formation damage and rising wellhead pressures which operators will need to address.
Estimation of Inter-Well Connections in Waterflood under Uncertainty for Application to Continuous Waterflood Optimization of Large Middle-Eastern Carbonate Reservoirs
Authors: Zhai Xiang , Wen Tailai , Matringe Sebastien
Published: September 2016

The management of large and mature waterfloods is a notoriously challenging exercise. The vast amount of data available usually cripples reservoir simulation efforts and operational teams usually revert to simple classical engineering calculations, diagnostics plots and maps to make their decisions. Some powerful technologies based on reduced-physics modeling have been developed over the past decade to address this issue. In this paper, we present one such approach that was designed for the management of a large Middle-East carbonate waterfloods.

The reservoir model used is based on the Surveillance Model proposed by Batycky et al. (2008) but differs from it in two aspects: the inter-well allocation factors are computed through the solution of a tracer equation rather than through streamline computations and the fractional flow behavior is estimated through an empirical model rather than computed numerically. Using the tracer allows an improved treatment of unstructured grids and dual-porosity systems, both features being important for the application of interest. Modifying the fractional flow model allows for the automation of the history-matching step. The model can thus integrate new data quickly and estimate the strength and efficiency of each inter-well connection.

An optimization algorithm is used to translate the reservoir management strategy of the asset team in terms of an objective function and a series of constraints at the well, well-group or facility level. Constraints such as voidage replacement ratios, surface facility limits, fracturing pressures can be integrated into the optimization engine to control the field.

A new uncertainty modeling process uses a Markov-Chain Monte-Carlo algorithm to evaluate the robustness of each recommended change. The less mature or less data-rich areas of the field are typically harder to calibrate and more uncertain. Decisions to change the rate of a producer or injector in those areas are more risky. The algorithm is able to quantify this risk to help the operator make a more informed decision. As the field gains in maturity, the algorithm shows how the model learns with new data and how the proposed decisions continuously gain in robustness.

The application of the methodology to giant Middle-East carbonate fields is discussed. The proposed methodology was able to integrate all relevant facility, well group, individual well and reservoir constraints but remains fast enough to be run daily as new data becomes available.
Effects of Confined Space on Production from Tight Reservoirs
Authors: Stimpson Brian C. , Barrufet Maria A.
Published: September 2016

A rigorous method is presented for incorporating confined space into thermodynamic modeling for use in compositional reservoir simulation. Capillary pressure is incorporated as a function of pore size, wettability, and fluid phase properties. Simulated reservoir production is compared for cases with and without including capillary pressure effects due to small pores. During thermodynamic modeling, oil and gas phases are assumed to exist at different pressures, which difference is the capillary pressure. This becomes significant for small pores and is described by the Young-Laplace equation. Including capillary pressure using this method effectively and rigorously couples pore size with the thermodynamic calculations involved in compositional reservoir simulation. The interfacial tension (IFT) required for capillary pressure calculations is determined using the Weinaug and Katz parachor method. These methods are incorporated into an in-house developed compositional reservoir simulator to predict changes in production. Results from modeling show changes in fluid behavior due to confinement. The phase envelope calculated including capillary pressure exhibits a decrease in the cricondenbar and increase in cricondentherm compared to the bulk space phase envelope. Therefore, the bubble point pressure decreases and two-phase flow is reached later in production from an oil reservoir. When the reservoir contains both oil and gas phases, the oil saturation is higher in confined space compared to bulk space. Simulation results show that in a tight oil reservoir, oil production rate including confinement is larger than when assuming no capillary pressure due to this higher liquid saturation. Therefore, produced gas-oil ratio is smaller. Implementation of capillary pressure into compositional reservoir simulation until present has been achieved by use of the Leverett j-function with and without IFT correction. The method proposed here is more rigorous in that capillary pressure is calculated based on pore size and fluid compositions. Thus, as fluid compositions in the reservoir change due to production, capillary pressure successfully reflects those changes.
A Rigorous Upscaling Procedure to Predict Macro-scale Transport Properties of Natural Gas in Shales by Coupling Molecular Dynamics with Lattice Boltzmann Method
Authors: Ning Yang , He Shuai , Liu Honglin , Wang Hongyan , Qin Guan
Published: September 2016

It is well known that shale formations exhibit multi-scale geological features such as nanopores in the formation matrix and natural fractures at multiple length scales. The key challenge in unconventional reservoir simulations is thus how to preserve fine-scale information in coarse-scale reservoir simulations for correct production forecasting and reserve estimation. Accurate prediction of shale permeability using numerical tools requires understanding of transport mechanisms in nano-scale, and upscaling from nano-scale to larger scale simulations. In our recent work (URTeC: #2459219), we presented the coupling of the molecular dynamics (MD) simulation with the lattice Boltzmann method (LBM) on multiple-scale digital rocks to estimate the transport property of shale matrix in micrometer scale. As an extension, this work is aimed to develop an upscaling workflow that integrates nanometer-scale simulations, micrometer-scale simulations and centimeter-scale simulations. The proposed approach allows calculating macro-scale transport properties of natural gas in shales with significantly reducing the loss of critical fine-scale (nano-scale) information.

The reconstructions of multi-scale shale digital rocks are performed using multiple imaging techniques, i.e. FIB-SEM, Nano-CT and Micro-CT. These experiments provide micro-scale pore architectures (∼nm), meso-scale mineralogical distribution (∼μm), and macro-scale natural-fracture network (∼cm), respectively. These multi-scale digital rock reconstructions are then utilized for the investigations of multi-scale transport properties of gas shales. This upscaling process can be summarized as the following three steps. (1) nano-scale transport properties in organic and inorganic structures are calculated using the non-equilibrium MD simulations. Representative organic (kerogen) and inorganic clay (montmorillonite) molecules are built upon their molecular formulas. Transport properties determined from MD simulations are then served as input parameters for LBM simulations in larger scale; (2) micro-scale properties of each component are mapped stochastically on its corresponding voxels in Nano-CT digital rocks. The meso-scale permeabilities of Nano-CT digital rocks are then calculated using the generalized LBM model in porous media; (3) the effective permeabilities of the macro-scale shale digital rock (Micro-CT) with micro-fracture networks are calculated using the generalized LBM model, in which the matrix permeabilities obtained from the step 2 and the transport properties of micro-fractures are served as simulation inputs in macro-scale.
A Transient Coupled Wellbore-Reservoir Model Using a Dynamic IPR Function
Authors: Garcia A. Posenato , de Sousa P. Cavalcanti , Waltrich P. J.
Published: September 2016

Conventional IPR models are used in coupled wellbore-reservoir transient simulations, even if bottomhole pressure conditions are assumed to be constant on the derivation of such IPR models. The dynamic IPR model proposed in this paper not only captures the relevant reservoir dynamics from the well perspective, but is also computationally more efficient than discretized models using hundreds of gridblocks to simulate the near wellbore region.

Any well-behaved function can be decomposed in a combination of sinusoidal functions. Hence, a sinusoidal bottomhole flowing pressure with a frequency varying from a given value down to zero is assumed as a boundary condition to the hydraulic diffusivity equation. The zero frequency corresponds exactly to the conventional IPR model since it is the steady-state condition. The analytical solution that calculates the flow rate for the sinusoidal pressures for each one of the frequencies is presented. Finally, the Dynamic IPR is defined as the low-order, linear ordinary differential equation that best approximates this solution.

It is a well known fact that the reservoir dynamics is relevant to the calculation of the flow rate in certain conditions, such as drawdown and pressure buildup well tests. A comparison between the Dynamic IPR function, the conventional IPR models, and the analytical solution is presented for these cases. The conventional IPR model gives unrealistic results, since it allows the flow rate to change instantaneously to the next equilibrium condition, as opposed to the Dynamic IPR which can capture the fully transient response. The Dynamic IPR showed excellent agreement with the true solution. Two different examples are presented in this paper showing the application of the Dynamic IPR: a reservoir well testing and a severe slugging well. With a given measured bottomhole flowing pressure, a comparison between the Dynamic IPR, conventional IPR and a reservoir simulation is presented. Once again, the conventional IPR model provides unsatisfactory results when compared to the Dynamic IPR. These results showed that neglecting reservoir dynamics in transient simulations might result in inadequate production forecasts, inefficient designs and eventually unsafe operations while using conventional IPR models.

This work points out some limitations in one of the common practices in the industry, which is the use of steady state IPR for coupled wellbore-reservoir transient simulations. The alternative Dynamic IPR herein proposed is computationally inexpensive when compared to discretized reservoir models while still being able to capture the transient well behavior and the steady-state solution.
An Assessment of the Probability of Subsurface Contamination of Aquifers from Oil and Gas Wells in the Wattenberg Field, Modified for Water Well Location
Authors: Stone C. H. , Fleckenstein W. W. , Eustes A. W.
Published: September 2016

The United States National Science Foundation has funded a Sustainability Research Network (SRN) focused on natural gas development in the Rocky Mountain region of the United States. The objective of this specific study is the assessment of the use of existing water wells to monitor the risk of the contamination by the migration of fracturing fluids or hydrocarbons to fresh water aquifers. An additional objective of the study is to modify existing risk estimates using the spacial relationships between the existing water wells and producing oil wells. This will allow estimates of single barrier failure and multiple barrier failure resulting in contamination to be projected for oil and gas wells in areas without surrounding water wells to detect migration, based on well construction type.

Since 1970, the Wattenberg Field in Colorado has a large number of oil and gas wells drilled. These wells are interspaced tightly with agricultural and urban development from the nearby Denver Metropolitan area. This provides a setting with numerous water wells that have been drilled within this area of active petroleum development. Data from 17,948 wells drilled was collected and analyzed in the Wattenberg field, allowing wells to be classified by construction type and analyzed for barrier failure and source of aquifer contamination. The assessment confirms that while natural gas migration has occurred in poorly constructed wellbores is infrequent, it can happen and that the migration risk is determined by the well construction standards. The assessment also confirms that there has been no occurrence of hydraulic fracturing fluid contamination of fresh water aquifers through wellbores. The assessment determines both the spacial proximity of oil and gas wells and surface casing depth to water wells to determine the utility of water wells to monitor migration in oil wells.
Role of Fluid Injection on Fault Activation During Hydraulic Fracture Stimulations
Authors: Baig Adam , Urbancic Ted , Viegas Gisela
Published: September 2016

Based on recent reports, there is little doubt that hydraulic fracturing can result in the generation of seismic events with magnitudes greater than zero as related to the activation of faults situated within or within proximity to reservoirs. The question that arises is whether fault activation is related to the presence of fluids and proppant or is related to perturbations in the local stress field. In other words, are these events triggered through stress perturbations or induced by pore pressure reducing effective stress?

Fault activation is also related to the degree of surface roughness, asperities and barriers to slip, frictional stress of the rock and the resulting rupture velocity. To derive a picture of the faulting and sub-faulting processes, we examine signals of a M>0 event associated with stimulation in the Marcellus formation as recorded near surface with low-frequency sensors along with the sub-faulting behaviour as observed in high frequency signals recorded close to the source. We investigate the dynamics of sub-fracture failures during the rupture process and growth of the overall fracture from initiation to rupture arrest, the role of asperities, roughness, fluids, the failure mechanisms (shearing versus tensile dominance of behavior), and the conditions under which induced-triggered failures may occur.

Based on our observations, fault activation was related to decreasing frictional resistance on the fault surface due to the presence of fluids. The increasing magnitude for sub-events during fault activation suggests that slip over a larger contact area such as an asperity and that fluid influence was dissipating.

Overall, failure was dominated by a shearing mode of failure, whereas the sub-fracture failures were mixed-mode, that is, more complex than a simple shearing process and included a strong tensile component of failure that evolved in time. However, from this example, it is difficult to ascertain if fault activation was triggered or induced; it appears both modes are plausible.
Wettability Alteration with Brine Composition in High Temperature Carbonate Rocks
Authors: Chandrasekhar Sriram , Sharma Himanshu , Mohanty Kishore K.
Published: September 2016

Injection of brine with tuned composition has been shown to give improved oil recovery from carbonate rocks. Contact angle studies, spontaneous imbibition and core flood experiments have shown that wettability alteration is responsible for this process. Possible mechanisms include mineral dissolution and ion exchange, which have been investigated by zeta-potential measurements and geochemical modeling of both processes. In this study, the core scale manifestation of these mechanisms is evaluated, and a geochemical model is developed for further insight into reaction pathways. Brines of different compositions were injected into carbonate cores with no oil and the effluent was analyzed for ionic composition. Seawater, sulfate-rich seawater, and dilutions of seawater were tested. Two phase oil displacement core floods were performed for the same brine cases to correlate the oil recovery to the geochemistry. A mechanistic model was developed using our in-house reservoir simulator UTCHEM-IPHREEQC for the wettability alteration process. The single phase core floods with all test brines indicate retention of SO42− within the core, seen by a delay in its effluent concentration reaching the injection concentration. Na+, Ca2+, Mg2+ and Cl− ions mostly behave as tracers in the system. In oil displacement core floods, formation brine recovers 40% OOIP on average and seawater recovers an incremental 7% OOIP. Sulfate-rich seawater and dilutions of seawater increase the recovery to 65-80% OOIP in secondary and tertiary modes, requiring more than 5 PVI. SO42− ion delay is not observed in the two phase core floods. Ca2+ concentrations remain high after 5 PVI of diluted seawater, indicating a slow dissolution process in the low salinity floods. The mechanistic model results were in good agreement with the single phase coreflood experiments and oil recovery experiments. The model showed that the reduction in surface concentration of naphthenic acids was responsible for altering the wettability on the injection of modified brines.
Flow of Multicomponent Gases in Carbon-Based Organic Nanopores
Authors: Kazemi Mohammad , Takbiri-Borujeni Ali
Published: September 2016

In the study of transport of gases in shale reservoirs, a special attention should be paid to gas transport in organic nanopores due to their nano-scale pore sizes and adsorption phenomena at the pore surfaces. Most of current studies are focused on the transport of single component fluids, mainly methane. The objective for this work is to investigate transport of multicomponent gases in carbon-based organic pores.

In this study, adsorption and transport of multicomponent gas systems in identical setups of graphite channels with rough surfaces are investigated using non-equilibrium molecular dynamics simulations (NEMD). Simulations are performed for two gas samples with different compositions for channel heights of 2 and 4 nm. For each simulation, the velocity, density, and mass flux profiles are computed. Moreover, the selectivity values of heaviest molecule (hexane) over other gas components are determined. Finally, diffusion coefficients of each gas component are computed and compared.

Based on MD simulation results, most of heavier gas components are adsorbed to the wall. Hexane, which is the heaviest gas component, has a higher tendency to be adsorbed to the channel walls compared to lighter gas components. Therefore, in real systems, most of the heavier components may stay in reservoir in adsorbed state. Furthermore, in contrary to previous studies in which plug-shaped flow profile were observed, parabolic-shaped velocity profile are observed due to presence of rough channel surfaces and heavier gas components. Based on the simulation results, heavier gas components have lower diffusion coefficients compared to lighter components.

This work is one of the few in-depth investigations of the transport of natural gas systems in organic pores. The results in this study can potentially modify the multiscale formalism of fluid flow in shale resources.
Truly Sustainable Building Blocks for Deepwater Field Development: The Need for Strategies Re-Definition in a Persistently Low Oil Price Scenario?
Authors: Beltrami Francesco , Hansen Kevin
Published: September 2016

The abrupt changes that occurred to the oil and gas industry at the end of 2014 and the persisting low oil price scenario appear to challenge the previous perception that the deepwater market was going to successfully continue its remarkable growth. In the light of the new economic scenario, the current deepwater technologies adopted in deepwater field development may be seen as too expensive or not affordable any longer. To survive, the deepwater industry needs to change and to re-think the way projects are carried out. This paper reviews the main ‘building blocks’ for deepwater field development planning, discussing how they are currently used and exploring more affordable, but technically robust, alternatives. The results of this original investigation are discussed and practical solutions are presented.

Operators need to continuously replace the reserves that are being produced. Deepwater blocks may have to be developed, sooner or later, even in a lower oil price scenario, to avoid the operator losing the rights on the same blocks. For these reasons, a discussion on the re-definition of field development strategies is of interest to the deepwater community. Clarifying which are the main building blocks and which is the more sustainable way to employ them in field development will hopefully help the recovery of the deepwater industry. The paper discusses the main technologies and components of a typical deepwater development, including subsea processing, and presents practical conclusions, identifying gaps, proposing alternatives - when desirable, and listing open issues that deserve further attention.

This paper is a contribution to the unavoidable discussion that both international operators (majors and independents) and national oil companies face when it comes to the future development of deepwater fields worldwide. The sustainability of the technical solutions required for such development is a key aspect and needs to be properly addressed. Reflecting on how field development options are presently identified and handled during concept definition and concept selection is now necessary. The re-definition of development strategies appears equally critical with respect to a possibly persisting low oil price scenario.