bluuebunny/crossref_metadata_2025 huggingface dataset:
Hydraulic Fracture Propagation in a Highly Laminated Shale Reservoir with Complex Natural Fracture Network - Case Study Using Higher-Accuracy, Full 3-D Simulation
Authors: Hussain Maaruf , Saad Bilal , Negara Ardiansyah , Elgassier Mokhtar , Agrawal Gaurav , Sun Shuyu , Abdullah King
Published: September 2016

It is often reported that around 60% of hydraulic fracturing stages are ineffective. If so, it is likely that the design accuracy is limited by the current state of modeling and hydraulic fracture (HF) simulations. Our study presents a new alternative – a full 3-D simulation with geomechanics coupled to fluid flow. With the conventional simulation, it is extremely hard to model opening of weak lamination (Lam) and nearly impossible to generate induced horizontal fractures against the vertical overburden stress. However, horizontal fractures are routinely evident in shale reservoirs as healed fractures observed along the bedding planes. Hence, the need and importance of a true 3-D simulator that could incorporate complex geology and dynamically simulate fracture propagation by accounting for realtime changes in geomechanics and fluid pressures. Case study uses shale reservoirs, which are heavily laminated with complex natural fractures (NFs). Numerical simulations consisted of four separate coupled modules - geomechanics, hydrodynamics, a geomechanical joint model for interfacial resolution, and an adaptive remeshing module. Reservoir stress condition, rock mechanical properties, and injected fluid pressure dictate how fracture elements could open or slide. Critical stress intensity factor was used as a fracture criterion governing the generation of new fractures or propagation of existing fractures and their directions. Simulation was run on a Cray XC-40 HPC system. Typical laminated shale reservoirs anisotropic geomechanical properties obtained from literature were used to estimate a 3-D geomechanical model and NF network. HF geometry was significantly different in the presence of weak bedding, compared to when bedding was strong enough to transmit crack tip stresses across the interface. Significant amounts of fracturing fluid can be diverted into creation of horizontal fractures, even when the pressure was below the vertical stress, once bedding discontinuities are activated. Choices of NF network and Lam thickness significantly affected observed fracture propagation. The value of 3-D modeling was clearly established. This method provides more accurate solutions for stimulation design optimization, e.g., landing points, number of stages, number of clusters, spacing between stages, and stimulated reservoir volume.
Impact of Internal Magnetic Gradients on Nuclear Magnetic Resonance Measurements and NMR-Based Pore Network Characterization
Authors: Tandon Saurabh , Heidari Zoya
Published: September 2016

NMR (Nuclear magnetic Resonance) measurements have been extensively used for characterizing porosity and pore size distribution with assumption of constant magnetic field gradient within porous media. However, internal gradients of magnetic field generated due to the presence of paramagnetic or diamagnetic centers such as clay particles can significantly affect NMR response and the resulting interpretation for pore-size distribution and porosity. In this paper, we quantify the impact of internal magnetic gradients and spatial distribution of matrix components such as clay minerals on NMR response using pore-scale NMR numerical simulations. We also quantify the influence of the aforementioned parameters on the NMR-based evaluation of porous media.

We used finite volume method to numerically solve Bloch equations (Bloch 1946) and simulated magnetization decay in porous media. We cross-validated the reliability of numerical simulations using analytical solutions given for spherical pores in different diffusion regimes. The model is then used for simulation of NMR response in the pore-scale images of sandstone and carbonate rocks. We developed synthetic cases based on actual rock images covering a wide range of spatial distribution of clay minerals (i.e., paramagnetic or diamagnetic centers) to quantify the sensitivity of NMR decay to internal magnetic gradients. We quantified the sensitivity of NMR response for distribution of clays as random dispersion in the rock grains, as thin laminae in the rock and as thin layers on the surface of grains.

The results showed that at low concentration (e.g., 0.3%-0.7%) of dispersed clay, there is negligible impact of internal magnetic gradients on magnetization decay. At higher concentration of dispersed clay (e.g., 5.1%-7.3%), we observed significant impact of internal magnetic gradients on magnetization decay. The presence of clay minerals can cause 53% variation in the location of transverse relaxation time constant (T2) and up to 67% relative error in assessment of dominant pore sizes. We also observed that structural clays even at high volumetric concentrations of 40% produce negligible effect on NMR measurements. Shale laminations containing clay were found to produce an effect of up to 17.5% on T2 relaxation time constant that could cause a relative error of 23.1% in estimates of dominant pore size in the rock. The outcomes of this paper can potentially improve conventional techniques of pore network characterization (pore-size distribution and pore volume) in the presence of clay minerals where internal magnetic gradients are not negligible.
Improved Characterization of Carbonate Rock Properties: A Multiphysics Integrated Approach
Authors: Kraishan Ghazi M. , Ma Shouxiang Mark , Dyshlyuk Evgeny , Al-Ofi Salah M. , Valori Andrea , Abdallah Wael , Crary Steve
Published: September 2016

Single subsurface measurement of formation properties cannot provide a complete assessment of the rock and fluid properties at reservoir conditions. The key to successful formation evaluation is through integration of data obtained with different physics, as demonstrated in this study of carbonate rock characterization.

Carbonate formations are complex owing to their complicated pore structure resulting from different depositional environments and diagenesis. Derived rock petrophysical properties from multiphysics measurements of acoustics, resistivity, dielectric, and nuclear magnetic resonance (NMR) are compared with the "true" rock properties determined directly through core analyses at ambient and/or reservoir conditions. 20 core plugs were studied at both fully and partially saturated states.

Results indicate that temperature is a major factor affecting the dielectric, NMR, and resistivity signals whereas pressure has less impact. Although, the selected samples were carefully chosen to represent the dominant lithofacies and rock lithologies, the NMR 1D porosity profile exhibit a heterogeneous nature for some of the plugs. After inversion of the dielectric data, the cementation factor and saturation exponent were obtained from both dielectric and resistivity experiments. In addition, the inverted shallow resistivity (Rxo) from dielectric agrees well with Rxo obtained from the resistivity measurement, demonstrating measurement consistency.

Integration of the multiphysics measurements enables improved characterization of carbonate rocks. The integration procedure is based on a mathematical algorithm comparing variability in the input parameters. The added value of the current work is shown when integrating and calibrating these results with logs. It enhances the petrophysical interpretation, reduces the uncertainty in some of the petrophysical parameters, and increases understanding toward better field development strategies.
Improved Field Recovery and Drilling Costs in Agiba Using ESP Reversed Y-Tool Dump-Flood Solution
Authors: Al-Kady M. , Selim A. , Omar A. , Ginawi I. , Bahgat A. , Abdelmotaal H. , Botros K.
Published: September 2016

Managing a waterflooding project always has its sets of challenges and associated costs. The use of advanced completions can aid in minimizing such costs, while increasing the field recovery. This study highlights the deployment of an advanced completion in a waterflooding project in a newly developed field located in the Egyptian Western Desert.

Initially, a specific area of the field started to experience a decline in reservoir pressure. The operator decided to drill a new injection well to provide the required pressure support in this area. Unfortunately, the amount of water produced by the field wells was not sufficient to feed an additional injection well. Several solutions were explored to tackle this issue. The most straightforward, but costly, solution was to drill a new water source well. Another proposed method was to rely on a natural dump flood, by perforating both the injection and production zones within the same wellbore. The pressure difference should create a "natural injection" effect. However, the study showed that this method would not provide the required injection rate.

Finally, a novel solution was selected to provide the required injection rate with the aid of an advanced completion. The flow was assisted with an electrical submersible pump (ESP) to control the injection rate. The pressure support was successfully provided by producing water from the producing zone to be reinjected into the target injection zone, all within the same wellbore. The effectiveness of the solution was confirmed with the aid of a real-time monitoring and surveillance system. Later, this aided in optimizing the production of other nearby wells.
Bitumen and Tar Deposition and Tar Mat Formation Accounted for by Multiple Charging, Trap Filling and Fluid Geodynamics
Authors: Mullins Oliver C. , Primio Rolando Di , Uchytil Steve , Zuo Julian Y. , Dumont Hadrien , Mishra Vinay , Pfeiffer Thomas , Achourov Vladislav
Published: September 2016

Deposition of organic solids high in asphaltene content (tar, bitumen) in reservoirs from natural processes is a routine occurrence around the world. Nevertheless, there is a bewildering array of deposition characteristics as shown in recent case studies. Sometimes this tar or bitumen (both are really the same material) is at or near the crest; sometimes it is on interlayers within a heterolithic sequence (baffles) or at the base of the reservoir which can be tens of kilometers away from the crest. Sometimes the bitumen deposition is such that the corresponding formation remains permeable; sometimes the tar zone is totally impermeable. Sometimes the tar at the base of the reservoir represents a more or less continuous increase in asphaltenes from the oil immediately above the tar; sometimes there is a sharp, discontinuous increase in asphaltene content from the oil to the tar. And particularly for upstructure bitumen, sometimes the bitumen is deposited throughout the entire producing interval (in a well); at other times the bitumen deposition is only at the base of the producing interval. This paper shows that ALL of these variable tar or bitumen characteristics can be understood within simple concepts that treat the dissolved asphaltene in crude oils and the deposited asphaltene within the same framework. This framework utilizes simple chemical solution characterisitcs that are formally expressed in the Flory-Huggins-Zuo Equation of State for asphaltene gradients with its reliance on the Yen-Mullins model of asphaltenes. Multiple charges of incompatible fluids lead to asphaltene deposition. The extent of slow, diffusive destabilization from density stacking charge fluids versus rapid destabilization from a secondary lateral fluid front controls much of the characteristics of deposited asphaltene. Consequently, the proximity of the well to reservoir charge points as well as petrophysical parameters of the formations are very important parameters. The ideas herein enable projection of the nature of asphaltene deposition away from a wellbore to other locations in the reservoir. This capability greatly assists the ability to understand the impact of asphaltene deposition on production.
First Autonomous Inflow Control Valve AICV Well Completion Deployed in a Field Under an EOR Water & CO2 Injection Scheme
Authors: Kais Ransis , Mathiesen Vidar , Aakre Haavard , Woiceshyn Glenn , Elarabi Amr , Hernandez Ricardo
Published: September 2016

Enhanced oil recovery (EOR) schemes utilizing CO2 and water injection often experience significant problems and challenges with short circuiting of CO2 gas and water between injectors and producers, thereby leaving significant oil behind. Presented herein is the description and results of a field trial of new downhole flow control technology designed to provide autonomous inflow control of produced fluids from each zone in multi-zone wells.

The new technology deployed involves integrating an autonomous inflow control valve (AICV) and a conventional (passive, non-autonomous) inflow control device (ICD) into a unique 3-position "sliding sleeve", shifted by coil tubing, to allow performance comparison between the two different inflow control devices as well as multiple flow control settings of each type. The AICV was designed (and lab tested) to selectively choke back or shut off flow of free CO2 gas and also high watercut (>99%), thereby significantly improving reservoir sweep and yielding higher oil production. The AICV opens or closes autonomously depending on sensed properties of wellbore fluids. Prior to installing the advanced completion, the multi-zone (vertical) trial well was extensively characterized using PLT and other log data, which was then inputted into a commercially available computer model to help design the AICV and ICD settings. The field trial was designed to evaluate the use of flow control in the EOR scheme over a wide range of flow rates and also to compare the two different flow control technologies at different settings within the same wellbore and reservoir condititions.

This paper presents the results of the world's first field trial of the AICV in a Water and CO2 injection scheme, and the world's first comparison with conventional ICD technology in the same well. In addition to lab tests, the early field trial results of the advanced flow control completion are compared with historical production and PLT data where the zones were comingled (without any downhole flow control). A performance comparison of AICV versus conventional ICD, along with conclusions, implications for other wells in the same field and other fields, and lessons learned, are all presented herein.
Leak Detection and Self Healing Pipelines Using Twin Balls Technology
Authors: Chalgham Wadie , Seibi Abdennour , Lomas Matthew
Published: September 2016

Healing leaks is always a priority in the oil and gas industry and plays a major concern to human safety. The time required to fix any leak has a direct relationship in determining the damages caused to the environment, industry and most importantly the number of lives lost caused by catastrophic pipe failures. Detecting leak size and location in pipelines with higher accuracy present major challenges to operators. This paper presents an innovative solution to detect leaks or potential future leaks and heal them instantly using Twin Balls Technology. The solution is based on establishing a relationship between leaks and its associated sound level. Knowing those sound levels precisely and how they propagate with respect to time from the leak source will help build the solution with higher precision. The solution consists of inserting two flowing smart balls into the pipeline. The first smart ball will be receiving acoustic data thanks to the sensors inside of it. Once the threshold of sound level is surpassed, designed thanks to multiple experiments, the smart ball will send a signal immediately to a second flowing ball responsible of ejecting a healing fluid. The healing fluid will flow towards the leaking outlet and close it instantly, preventing any further damages. Also, the first ball will alert instantly the supervisors via wifi monitoring and text messages describing the leak size and location. Twin Balls Technology could be used in pipelines of different sizes and flowing fluids.
A Pigging Model for Wax Removal in Pipes
Authors: Huang Qiyu , Wang Wenda , Li Weidong , Ren Yijie , Zhu Fangda
Published: September 2016

Pigging is widely used in pipelines for wax removal. However, pigging operation relies heavily on "rules-of-thumb." Because of its complexity, rather limited pigging models were presented to predict the wax removal mechanics in past decades. This work aims to develop a pigging model for wax removal in pipelines. A unique experimental facility was designed and constructed for simulating pigging operation for wax removal in pipelines. This facility comprises five main parts: an experiment system, a wax casting system, a motor and control system, a measurement and data acquisition system, and a special designed pig system. The mixture of crude oil and field wax deposit was cast inside the test section to carry out the pigging experiments with disc and cup pigs. It was found that hardness of the scraping element in pig has a profound effect on wax removal, and this effect depends on the wax thickness on the pipe wall tightly. A pigging model, which could well explain the effects of wax thickness, wax hardness, pipe diameter, pig geometry as well as hardness of the scraping element in pig, was established based on the experimental findings. To the best of our knowledge, this is the first time to incorporate the effect of hardness of the scraping element in pig on wax removal into a pigging model. 17 sets of pigging experiments were used to verify the developed pigging model with an average relative error of 10.69%. The pigging model developed in this work could be a practical tool in designing economic and safe pigging programs.
Managing Competency in a Low Oil Price Environment: SPE Offers an Expanded Competency Management Tool to its Members
Authors: Jain Alok , Donohue Bradford R.
Published: September 2016

In keeping with its mission to provide its members with opportunities to enhance their technical and professional competence, SPE launched a Competency Management Tool (CMT) in partnership with IHRDC in October 2014. In order, to gauge membership interest, this initial release of the CMT included a limited number of key operating company technical jobs. By June 2015, some 1,000 members had used the tool and provided very positive feedback. Encouraged by this response, SPE decided to expand the number of jobs in the tool such that a larger cross-section of its members could benefit from it. This meant expanding CMT's operating company-focus to include drilling contractors, EPC contractors, integrated service companies and the student community. The expanded CMT was launched in late September 2015. It now includes 41 job competency models, 9 disciplines (Production Engineering & Operations, Project and Facilities Engineering, Well Engineering, Health, Safety, and Environment, Subsurface, Business Development - Operating Companies, Business Development - Service Companies and Contractors, Supply Chain, and Entry level Engineers), 308 competency units and over 1,200 training resources. The basic features of the tool have also been enhanced to provide quicker assessment results and easier navigation. Since September 2015, some 1,900 users have accessed the tool, 1,263 of them have started a self-assessment and 210 have completed the self- assessment. It is encouraging to see that the composition of the users adequately represents the broad geographical spread of SPE's membership, and all of the job models are being used, although a higher percentage of users are concentrated in only four or five disciplines. The paper describes how using the CMT will add value for students, young professionals, mid-career or senior professionals, and also for companies that do not have an in-house Competency Management System. The user feedback over the past 18 months has been critically analyzed to develop insights about the use of the tool and whether SPE is meeting its key objectives in introducing the tool. While the overall usage numbers are lower than expected, it is believed that that is a result of lack of awareness about the tool rather than its usefulness. The usage data clearly shows that a higher percentage of users are young professionals and career professionals, the two categories that SPE was specifically targeting for accelerating competency development to address the industry concerns about the "experience gap" stemming from a large-scale exodus of older professionals. As the industry recovers from the oil price shock, the availability of the CMT as a low-cost alternative (free for SPE members) to develop and manage a competent workforce should serve it well to get back quickly on its feet.
Multiphase Flow Meter Performance Evaluation Using Live Hydrocarbon Flow Loop Mimicking Real Field Conditions
Authors: Benlizidia I. , Al Jarri A. S. , Al Anazi M. A.
Published: September 2016

Over the last two decades, multiphase flow measurement (MPFM) has become accepted by the Oil & Gas industry worldwide. Nevertheless, the operators are in a pressing need to assess the measurement performances of each MPFM technology. Generally, this is performed through field trials of one or several MPFM technologies against typically a conventional test separator.

In this paper, we will describe an accelerated new and cost effective methodology to evaluate the metrological performance of a multiphase flow meter in specialized facilities with live hydrocarbons mimicking the real field conditions.

In this methodology, multiphase flow loops are used to reproduce real field conditions with live hydrocarbons fluids where pressure is the key parameter when attempting to mimic real multiphase flow in such controlled environment. Associated with proper test procedure design, these facilities have offered a framework to evaluate multiphase flow meters using live Hydrocarbons under comprehensive conditions in terms of flow regimes, flow rates, phase fractions distributions, salinity, pressure and temperature, ensuring good stability and very high level of accuracy in the reference measurement. The paper guides the reader through the technical considerations required to identify the flow loop test conditions and requirements and set standard procedures from an operator point of view to perform a successful performance evaluation. It also provides case studies where the performance benchmarking obtained in the flow loop has been confirmed and verified in real field conditions.

Using a live hydrocarbon multiphase flow loop for evaluating and quantifying metrological performance specifications for multiphase flow meters has shown to be a very powerful and cost effective tool when associated with proper testing procedure design. This new approach also provides results that are translated to an expected and verifiable performance for real field applications with all their associated complexities.

This paper provides a new testing methodology for any multiphase flow measurement technology where the conventional ways of testing may fail; it also provides valuable insight to multiphase flow meter performance measurement evaluation and specifications definition from an oil operator point of view.
De-risking Polymer Flooding of High Viscosity Oil Clastic Reservoirs - A Polymer Trial in Oman
Authors: Anand Adi , Ismaili AbdulRahman
Published: September 2016

A long term polymer injectivity trial has been conducted in a medium-high oil viscosity field in Oman, with a suite of objectives to assess the feasibility of the high viscosity polymer concept, evaluate alternative polymers and de-risk the low-salinity polymer hybrid for field implementation.

An integrated analysis of this injectivity trial is presented. Performance in the field during injection of low and high molecular weight (MW) polymer in hybrid with low salinity water is analysed along with interpretations of the intermediate water injection, shut-ins, pressure fall-off and step rate test at the end.

The analysis is based on simulation models to history match the pressure response in the injector during the polymer trial. Key realizations focusing on two aspects – polymer rheology and wellbore/reservoir fluid propagation mechanism – are presented that were used to history match baseline water injection, low and high MW polymer injection, low salinity water injection and polymer low salinity water hybrid. Other sources of information – step rate test and pressure fall-off tests conducted during the trial – were interpreted to validate the conclusions from the HM model.

The study highlighted the risks of either inducing fractures or reactivating an existing fracture network in the reservoir during the polymer injection. Different sources of data indicated fracture pressure lower than anticipated. The dynamic characterization of the fractures – propagation and shrinkage – depending on the injection rate, injection fluid type and viscosity are found critical to explain the entire polymer trial response. The study also highlighted that capturing the polymer rheology adequately in the model, based on laboratory data, helps to explain the trial response. Changing well conformance has been found another important parameter in explaining the trial response. Finally, using the baseline water injection to ensure the permeability field is adequately modelled constitutes another step in understanding the polymer trial.
Experimental and Theoretical Study of Water-Solute Transport in Organic-Rich Carbonate Mudrocks
Authors: Padin A. , Torcuk M. A. , Katsuki D. , Kazemi H. , Tutuncu A. N.
Published: September 2016

The objective of this research is to determine the physicochemical processes underlying water and solute transport in organic-rich source rocks. Experiments were performed on Eagle Ford shale samples composed of organic-rich, low-clay carbonates using a high pressure triaxial assembly with novel design. Experimental results were successfully matched with a numerical chemical transport model. The mathematical formulation of this model relies on the chemical osmosis principles driving low-salinity brine into high salinity core samples. The results of this research should be beneficial for design of EOR processes in organic-rich shale.

A custom designed experimental apparatus was constructed to conduct flow tests. The apparatus is capable of maintaining core samples at reservoir pressure, temperature and confining stress. In addition, a new mathematical model was formulated to simulate flow into the core as a porous medium rather than as a molecule-selective membrane. This new model is based on the following principles: (1) the solvent (low-salinity water) selectively enters the pores by diffusion mass transport and (2) the dissolved salt molecules (which are ionized) are restrained by internal electrostatic forces from diffusing in the opposite direction of the low-salinity brine molecules entering the pore network.

The mathematical model closely matches the experimental results and, more importantly, only very few assumptions were made in matching experiments. For instance, the critical model input data, such as permeability, porosity and rock compressibility, were obtained from flow experiments on twin cores, and the diffusion coefficient was chosen by history matching. The strengths of the numerical simulation include: (1) the mathematical model is based on the mass transport fundamental principles, (2) the model does not require the use of the ambiguously-defined membrane efficiency term, and (3) the chemical potential gradient is the reason for the low-salinity brine entering the high-salinity brine cores to generate osmotic pressure within the cores. The latter implies that osmotic pressure is the consequence of water entering the cores, not the cause.
Stress Dependent Permeability of Carbonate Rock
Authors: Hamid Osman , Osman Haytham , Rahim Zillur , Omair Ahmed
Published: September 2016

Permeability is one of the most important parameters in formation evaluation, reservoir characterization, and hydrocarbon production. There are many methods in the industry to model in-situ permeability, but it is also critical to know that permeability decreases with the increase of effective stress as has been reported in many case studies i.e. permeability is sensitive to changes in stress and pore pressure. In this study, a relationship between permeability, porosity, velocity and effective horizontal stress is developed for carbonate reservoirs using both core and field data.

In-situ horizontal stress is related to permeability for several reservoirs around the globe. This paper addresses fundamental controls on stress dependent permeability, as identified through analysis of core samples. The model developed provides a description of effective stress and explains the dynamic impact of geomechanical stresses on key production parameters in an effective way. This will lead to a more robust simulation model and history match for the life of the reservoir.

Core plug samples from carbonate formation were tested for conventional measurement (porosity, permeably, and grain density), while acoustic slowness is obtained by wireline and/or LWD measurement to create empirical correlations between permeability, porosity, velocity and effective stress. The correlations show a good agreement with available data that are commonly used in the industry for carbonate.

The developed workflow is presented to improve evaluation and enhance the productivity and management of stress-dependent reservoir, also predict sweet spots, optimize completion and predict production that will help in the development of both conventional and unconventional reservoirs.
A Simple Unified Pressure Transient Analysis Method for Fractured Waterflood Injectors and Minifracs in Hydraulic Fracture Stimulation
Authors: Hoek Paul van
Published: September 2016

Pressure Transient Analysis (PTA) is commonly used in Industry to estimate parameters such as dimensions (length, height) and skin of induced (hydraulic) fractures, and reservoir permeability. PTA interpretation methods are well established for the limiting cases of ‘low’ leak-off [Mini-Frac Analysis (MFA) of stimulation hydraulic fractures] and ‘high’ leak-off [Injection Fall-Off (IFO) analysis of waterflood-induced fractures]. However, traditional methodologies used for these two limiting cases differ fundamentally and there exists no established approach for intermediate leak-off, in spite of many efforts to date.

We present exact 3D simulations of hydraulic fracture propagation at arbitrary rate and for arbitrary leak-off (from very low to very high), followed by fracture closure as a result of shut-in and after-closure reservoir flow. Based on the trends resulting from these simulations, we propose a novel very simple analytical PTA method for estimating fracture dimensions, skin, leak-off coefficient, and reservoir permeability. This method is applicable both to fractured waterflood injectors and mini-fracs in hydraulic fracture stimulation. It presents a consistent approach to before-closure analysis (BCA) and after-closure analysis (ACA).

We compared the exact simulations with our novel analytical PTA method, and with more conventional MFA and IFO approaches, such as g-functions, square root time, and other existing BCA and ACA methods. For all these cases, it is demonstrated that the currently existing approaches present limiting cases for either low leak-off (MFA) or high leak-off (IFO) of our proposed PTA method, and that our novel methodology provides superior results to the existing approaches particularly in the intermediate leak-off range. We also use our numerical methodology to demonstrate that more recently proposed analysis methods using generalized versions of the Agarwal/Bourdet derivative do not necessarily result in a ‘correct’ interpretation, in particular with respect to identifying the point of fracture closure. With respect to the latter, we also demonstrate that often identification of fracture closure from PTA will be virtually impossible.

Finally, we apply our PTA method to a few field cases, thereby demonstrating its simplicity of usage.
Delineating Overburden Anomalies through Dip-Constrained Tomography for Improved Reservoir Imaging in an Offshore Carbonate Field
Authors: Waqas Muhammad , Nakayama Shotaro , Benson Mark , Goraya Yassar , Kleef Franciscus van , Macri Giuseppe , Sroka Agata , Mills Keith , Cowley John
Published: September 2016

Overburden (shallow) anomalies such as channels, sink holes, or karst features pose challenges for seismic time imaging, resulting in an obscured image below the anomalies i.e. pull-ups or push-downs. These anomalies can propagate down to the reservoir masking the image and create structural uncertainties. These relatively small scale (< 1 – 2 km) overburden anomalies cannot be resolved with conventional depth imaging usually, based on migration velocity analysis and residual move out (RMO) minimization only.

This paper proposes the application of dip-constrained tomography, in combination with RMO tomography to help resolve these shallow anomalies. Although the method has been widely used elsewhere e.g. in offshore Brazil and North Sea (Chen et al., 2012, Guillaume et al., 2013, Carotti et al., 2015 and Hollingworth et al., 2015), this is the first time it has been applied in a carbonate oilfield in offshore Abu Dhabi.

An accurate velocity model is required for seismic depth imaging. The velocity model is optimized using a tomographic technique which is a non-linear optimization process with relevant constraints imposed. The data are migrated using an initial velocity model and common image gathers are obtained. RMO is defined in a cost function and non-linear tomography finds a velocity model minimizing the cost function. An additional structural constraint in the form of an offset-dependent dip constraint is introduced in the cost function for minimizing the misfit between the offset-dependent dip of the events and the expected dip.

Dip-constrained tomography was able to obtain a high resolution velocity model in the overburden and provided a robust seismic image essentially free of pull-up and push-down effects in the reservoir. The structural uncertainty in the reservoir was subsequently reduced. Inverting the dip term together with RMO term can potentially correct image distortions e.g. pull-ups and push-downs and focus the image simultaneously. The refined subsurface image can help optimize the reservoir model with less structure uncertainty and can enhance the production profile by providing more flexibility in well design and planning. The methodology was applied on a pilot area which gave quite encouraging results and leads to extend the pre-stack depth imaging to a full-field application.
A Methodology to Integrate Multiple Simulation Models and 4D Seismic Data Considering Their Uncertainties
Authors: Assunção Germano S. , Davolio Alessandra , Schiozer Denis J.
Published: September 2016

Traditionally, integration between 4D seismic (4DS) and simulation data has been performed considering the 4DS data deterministically. However, there are uncertainties in the response of seismic. The goal of the methodology presented in this work is to compare the changes of dynamic properties estimated from 4DS and simulation models considering the uncertainties inherent to both data.

The relevant reservoir uncertainties can be combined to generate multiple simulation models, which provide maps of dynamic changes, such as pressure change (Δp) and water saturation variation (ΔSw). Available 4DS can also be used to map dynamic changes. Through a stochastic seismic inversion, multiple ΔSw and Δp maps can be obtained from 4DS. After selecting a proper scale (scale transference), we compare the dynamic maps from seismic and simulation data using probabilistic density functions (PDFs), establishing levels of agreement/disagreement between 4DS and simulation data.

To validate the methodology we use a synthetic dataset, with moderate complexity and seven uncertainties mapped, such as fault transmissibility, porosity, facies, and permeability. 500 maps of ΔSw and Δp from 4D seismic were generated from prior probabilistic seismic inversion. 500 simulation models previously calibrated using well production data generated the set of 500 maps of ΔSw and Δp from simulation. Applying the methodology, we identify four regions: (1) reservoir locations where both estimates (seismic and simulation) are similar, showing regions properly calibrated, (2) locations where simulation estimates are more precise than 4D seismic, (3) reservoir locations where the data sets indicate divergent estimates, and (4) 4DS estimates are more precise than simulation.

This information can be very useful to guide data integration. As an example, we show that region (4) can be used to select the simulation models that reproduce ΔSw or Δp behavior from 4DS, since 4D seismic data is more precise than the simulation estimates in this region. Other useful information from the proposed methodology is that the reservoir zones identified as region (2) can be used as a constraint to reinterpret 4D seismic data, as simulation estimates are more precise.

The methodology is a new way to evaluate the information from 4D seismic and simulation data considering uncertainties. The identification of these four regions can be useful in the parametrization phase of the history matching procedure (a complex process), as an additional tool to understand the properties in this procedure. The methodology also indicates possible locations to use reservoir engineering constraints to improve seismic interpretation, in regions where estimates from simulation are more precise than 4D seismic data. Moreover, we can use the methodology to determine critical reservoir locations to be reevaluated, those presenting disagreement between the two data source.
Planning For Uncertainties in Gas Composition: Reduce Project Risks by Early Adoption of a Robust Gas Processing Concept
Authors: Chilukuri Pavan , Bowerbank Gary
Published: September 2016

This paper demonstrates that selecting a gas processing concept that is robust against changes in predicted gas composition during the maturation of (associated) gas projects reduces the risk of schedule delays and cost creep while potentially presenting opportunities to deliver first hydrocarbons to customers earlier.

During early project phases, the availability and quality of data on the specific field to be developed are usually limited. Consequently, project teams have often been left with two options when designing gas processing facilities. The first option is to rely on old data, data from well tests of questionable quality and/or data from analogue fields, if available, in order to form the basis of their design. This brings relatively high risk of having to redesign once higher quality data become available. Design alterations may delay the schedule to first oil/gas and lead to increased costs and erosion of the overall project value.

The second option is to wait for new well test data to become available before starting work on the gas processing facilities. This approach, though preferable, can result in costly schedule delays and does not guarantee the delivery of accurate data on which to predict the gas composition and base the gas processing design.

Appreciating this uncertainty is the first step in mitigating the risk. The second step is selecting a gas processing concept that is robust against flow and compositional deviations. In this way, the design of the gas processing facilities can go ahead at a low risk before full appraisal of the field is complete. This may enable parallel project phasing by starting the engineering procurement and construction (EPC) phase for the gas processing facilities during field appraisal.

Shell believes that an effective gas processing line-up of an acid gas removal unit (AGRU) that utilises the Shell Sulfinol-X all-in-one amine technology along with a selective acid gas enrichment unit (AGEU) combined with sulphur recovery units (SRU) and sulphur dioxide (SO2) tail gas treatment provides the robustness to deal with high compositional uncertainty for the gas.

The novelty in this paper is recognising that robust gas treating line-ups such as the one described above can have operational advantages and enable developers to secure their licence to operate by meeting emission restrictions. These line-ups can also have additional project execution/schedule advantages that add value to a project.

Specifically, this paper will demonstrate that the small additional capital expenditure required for the proposed robust design is more than compensated for by the acceleration of the project resulting in an overall improvement to the net present value. Additional benefits to the project will be ease of operation, simplicity and ultra-low emissions.
Challenges During Execution, Construction and Operational Readiness Phase of Surface Facilities in a Full Field Polymer Flood Project
Authors: Mohanram Santosh , Bhaumik Premashis , Jain Shagun
Published: September 2016

This paper is a follow up paper to SPE-169709-MS and discusses key challenges in Surface Facilities Project implementation during the Construction and Operational Readiness phase of the Project and presents available performance results from the full field implementation.

The key areas discussed include (a) operational difference in the available technologies for high concentrated polymer dissolution, (b) transfer of high viscous Polymer Mother Solution with minimum viscosity loss - refinement of the pressure drop calculations based on actual experience (c) efficacy of pumping facility with high viscosity non Newtonian liquid flow with varying turn down-challenges and lessons learnt based on field experience and (d) supply chain strategy for polymer logistics

The paper also presents preliminary performance results from the full field implementation of world's largest single polymer injection facility as compared to expected challenges and perceived mitigation during design phase.
Self-Sealing Isn’t Just for Cracks: Recent Advance in Sour Well Protection
Authors: Dieguez E. Sevilla , Bottiglieri A. , Vorderbruggen M. , Saeed Y.
Published: September 2016

Cementing sour wells can be very challenging; even when best practices are followed, the integrity of the cement, casing, and/or tubing can be jeopardized. In such cases, challenging and costly remedial work is necessary due to the complicated nature of the environment. A safe, cost effective way to prevent the need for remedial work is the use of self-sealing systems; however, until now, there was no data that validated self-sealing systems’ capability to tolerate exposure to H2S. This paper focuses on the newly discovered ability for the self-sealing systems to withstand exposure to H2S while maintaining self-sealing properties.

To confirm that the self-sealing material is uninhibited by H2S, a gas mixture of H2S in nitrogen was bubbled through a mixture of self-sealing material and water. The concentration and rates used were picked to mimic a standard sour well’s condition allowing the testing to recreate the challenging well environment. The self-sealing material was then added to the cement slurry and transferred to the crack/seal equipment for testing.

The results from the experiment were compared to a self-sealing slurry with the same components but in which the self-sealing material had not been exposed to H2S. Both systems were able to seal multiple times, validating the ability of the exposed material to withstand H2S exposure. The finding from this study opens the door for self-sealing cements to address several kinds of corrosive gases. Because the system was able to withstand exposure to such a strong gas, it will likely be able to tolerate weaker corrosive gases such as CO2.

The discovery from this experiment promotes a new use for self-sealing cements. No longer will their use be limited to cracks in the cement matrix but also as an extra precaution when working in sour wells and corrosive environments.
Numerical Investigation of the Effect of Nonuniform Fracture Aperture of Eagle Ford Outcrop Maps on Production Performance
Authors: Sun Jianlei , Schechter David , Rui Zhenhua
Published: September 2016

Nonuniform fracture aperture not only might affect initial reservoir fluids in place, but also production behavior. Previous experimental work has already demonstrated the importance of nonuniform fracture aperture on permeability and residual oil distributions. This study investigates its impact on unconventional liquid reservoirs through outcrop analysis of Eagleford maps, unstructured gridding, and reservoir simulation of hydraulically fractured horizontal wells.

Previously documented Eagleford outcrop maps are digitized as fracture patterns. Fracture networks for reservoir simulation are generated by duplicating the fracture patterns along horizontal and vertical directions. Then, in order to evaluate production performance of the complex fracture networks, unstructured gridding algorithms are developed to discretize the fractured reservoir domain. Furthermore, previously CT-measured lognormal fracture apertures are populated along each fracture. Finally, the impact of nonuniform fracture apertures on production performance is evaluated under different closure stresses and compared with corresponding uniform fracture apertures.

The complex fracture networks generated from outcrop maps show very high natural fracture density than what we usually observe in the literature about Eagle Ford formation. Fractures with nonuniform apertures show responses of finite fracture conductivity. In the early period, fracture drainage is observed around the horizontal well, even if fractures in outcrop maps are very well connected. At the later period, matrix-fracture transient flow dominates the production, showing a long tail in production rate plots. In addition, stress-dependent nonuniform fracture apertures affect cumulative oil production. The higher the closure stresses, the higher the chance the aperture decreases, and thus the lower the production performance. Moreover, when fracture mineralization is taken into account, the decrease of nonuniform apertures can bring down the cumulative oil production by almost half. Furthermore, the cumulative oil profile of nonuniform apertures is bounded by those of arithmetic and harmonic averaged apertures. Therefore, it is possible to quickly estimate well production using uniform fracture apertures that are obtained by applying averaging techniques to nonuniform apertures.

This paper proposed a workflow to simulate well production performance of Eagle Ford outcrop maps with nonuniform fracture apertures. Besides, the impact of nonuniform fracture apertures due to closure stresses and mineralization is presented together with comparisons with uniform fracture apertures.