bluuebunny/crossref_metadata_2025 huggingface dataset:
Features of the Well Test Interpretation in Complicated Conditions of Intensive Segregation of Phases in the Wellbore and the Manifestation of the Effects of Abnormal Pressure Growth.
Authors: Shchurenko Aleksandr , Arbatskii Timur , Dadakin Nikita , Rymarenko Konstantin , Nukhaev Marat , Musin Roman
Published: October 2018

During well tests on producing wells in oil and gas reservoirs on non-stationary flow regimes, the most common technology used is shutting a well on a wellhead, due to little technical and economic resources needed. Using these techniques however willingly implies a range of complicating factors, which have a direct influence on quality of the data on hydrodynamic properties of a reservoir, necessary for further production engineering.

This paper describes the physical-chemical mechanism and diagnostics of such complicating factors as segregation processes in the wellbore, which substantially distort the real pressure response of studied reservoir hydrodynamic system. The paper proposes a method of phase redistribution diagnostic, gives assumptions of causes of complicating segregation effects. In addition, the study suggests some technical and interpretational solutions aimed at improvement of quality and productivity of well tests.
Effective Zonal Isolation in Horizontal Wells: Mitigating Negative Impact of Mud Channels
Authors: Kolchanov Petr , Perroni Dominic , Medvedev Anatoly , Gao Yan , Tercero Randy , Todd Larry , Lungwitz Bernhard , Cowan Kenneth Mike , Turner William
Published: October 2018

Currently, hydraulic isolation of wells drilled with nonaqueous fluids (NAFs) relies heavily on the elimination of mud from the annuli before the placement of cement. Failure to expel all NAFs will result in residual fluid channels that will compromise well integrity and can even serve as nonproductive communication pathways during subsequent stimulation treatments. To mitigate this risk, an interactive cementing system is presented that is designed to reduce conductivity of the residual mud channels.

Although mud removal remains an integral part of the cementing process, this new cement formulation was developed to improve zonal isolation in the case of poor mud removal. The unique cement system reacts with the hydrocarbons present in NAFs, leading to a reduction of channel permeability and mobility. This significantly improves the likelihood of hydraulic isolation. Specialized testing protocols were developed to enable the demonstration of the capabilities of this new system. In addition, API testing methods and analytical techniques were used to optimize the slurry.

The development of the new cement system focused on the optimization of the active component concentration to give a favorable interaction with NAF, and at the same time, minimize the effect on cement rheology and mechanical properties. Procedures developed in-house demonstrated that the new system effectively reduces hydraulic conductivity of microannuli as well as channels up to several tenths of inches in size. Zonal isolation laboratory experiments were extrapolated to predict whether the modified channels can withstand the range of differential pressures typically seen between neighboring fracturing stages. This is the most critical operation that the cement sheath would be subject to.

Field tests are on-going at the time of writing this manuscript, and the preliminary results will be presented and discussed in this paper.
Image Reconstruction in a Tomographic Multiphase Flow Meter: A Greedy Compressed Sensing Approach
Authors: Al-Shuhail Shamael A.
Published: October 2018

The need for flow measurements throughout the production cycle has led to the development of a variety of multiphase flow meters. An ultrasonic tomographic multiphase flow meter is being developed in which it can potentially replace radioactive and invasive types of multiphase flow meters. The meter is configured to generate cross-sectional images of the flow inside the pipe in a non-invasive manner yet with direct contact to the fluid. Image reconstruction is generally carried out via inversion which requires a high level of computation complexity and processing time. It can be further challenged by the limited amount of data available. Compressed Sensing (CS) optimizes the conventional structure for data acquisition and compression. CS is based upon recovering certain data from very few measurements. Loosely speaking, most CS algorithms fall into either two categories; convex optimization recovery and greedy pursuits. In this paper, CS greedy pursuit algorithms are used to reconstruct sound speed images to find the most suitable algorithm in terms of image quality. Specifically, we made a comparative analysis of three greedy CS algorithms; Orthogonal Matching Pursuit (OMP), Compressive Sampling Matching Pursuit (CoSaMP), and Fast Bayesian Matching Pursuit (FBMP). We further compare the CS greedy reconstruction results to a conventional approach for image recovery based on the least-squares problem. Simulation results show that CS algorithms highly outperform the conventional approach for image recovery. Results demonstrate that high quality image recovery can be achieved using these simple greedy pursuit algorithms, sometimes even at increased system efficiency. Out of the three greedy algorithms, CoSaMP shows the highest quality for image recovery. Results also suggest that careful selection of the number of measurements used for recovery is necessary to obtain an accurate image reconstruction. As presented in this paper, our purpose is to adapt a CS approach, specifically greedy pursuit algorithms, for an efficient and an improved reconstruction of images generated by the ultrasonic tomographic multiphase flow meter to accurately quantify phase fractions in producing oil wells.
Cyber Security, the Cloud, and Oil and Gas
Authors: Black Peter
Published: October 2018

The rapid acceleration in the adoption of cloud services has increased the focus on cyber security. While data protection and privacy have always been key concerns in the oil and gas industry, this has frequently been achieved by isolating networks and strengthening perimeter defences. However, the weaknesses in this approach have been demonstrated, and it has masked poor practices in many areas. This paper will argue that the advent of cloud technology should not be regarded as a further challenge to security, but an opportunity to dramatically revitalise and improve a company's defences.

We will present a systematic overview of the kind of hybrid architecture that is increasingly common in many oil and gas companies, with on-premises and cloud systems. We will examine the key areas of authentication and authorisation and examine how these must evolve to address the cloud. We will also look at key pain points, like systems integration and legacy platforms, and examine how these are accommodated in a cloud-first architecture.

In examining the issues involved, we will see that cloud does not really introduce new security challenges but tends to highlight problems with existing practices. Historic failures to implement federated identity, or to secure and patch individual systems, or to allow unencrypted and largely insecure SQL access to corporate databases, represent a clear and present danger. By returning the focus to system security, and moving on the conversation from perimeter defence, cloud is providing a valuable service. Interestingly, this new technology also provides a range of answers, as we'll discuss, but it cannot be a universal panacea.

While adoption grows daily, cloud is still relatively novel to many companies. The lessons learned across multiple large-scale implementations of cloud technology in production data management allows us to derive general, vendor-independent guidance on cloud architectures, cyber security issues that must be addressed, and best practices that should be followed.
Progress Towards an Oil and Gas Industry Alternative to Mea Triazine in Hydrogen Sulfide Mitigation
Authors: Taylor Grahame , Wylde Jonathan , Oliveiro Antonio Pedro , Smith-Gonzalez Monica
Published: October 2018

Hexahydro-1,3,5-tris(hydroxyethyl)-s-triazine (MEA-triazine) is by far the most ubiquitous H2S scavenger used globally and occupies at least 80% of the available oilfield market. While almost the perfect scavenger in terms of kinetics and H2S uptake, this product does suffer from a number of undesirable effects which are usually tolerated or managed by various engineering modifications. For example, pH elevation causes scaling issues, deposition of intractable polymeric solids and increased ethanolamine load in crudes entering a refinery are some of the most prominent. A new scavenging technology has been developed that offers an alternative to triazine. This chemistry has undergone successful field trials and roll out in the US. The guiding principles in the design of this technology were to achieve, equal or better scavenger efficiency compared to triazine, equal or better reaction kinetics compared to triazine, "best in class" solids control, minimal pH impact, cost competitive with triazine, no impact on fluid separation and minimal refinery impact. The design, development, properties and field trial results for this exciting new technology are discussed as well as a critical evaluation against the aforementioned triazine industry benchmark.
Experience in Implementation of Polymer Flooding on East Messoyakhskoye Oil Field
Authors: Zagrebelnyy Evgeniy , Glushenko Nikolay , Komarov Vladimir , Nemirovich Gennadiy , Ilyasov Ilnur , Sugaipov Denis , Ushmaev Oleg , Pleshanov Nikolay , Iskhakov Ruslan
Published: October 2018

Development of reservoirs with high oil viscosity is usually challenging because of requirement to apply comlex technologies for economical efficient oil recovery. East Messoyakhskoye oil field is a complex project both from geological caracteristics (viscous oil with viscosity 111 cP, highly heterogeneous reservoir with permeability 50-2500 mD, presence of gas cap and aquifer) and due to its remote location (arctic climatic conditions, no transport and industrial facilities).

Main reserves are located in reservoir PK, senomanian formation. At the field development plan stage calculations showed requirement of flooding for reservoir pressure maintenance, but waterflooding expected to be risky due to fingering and it was obvious that for efficient reservoir development enhanced oil recovery methods should be considered.

This paper presents choosen enhanced oil recovery strategy, the way passed in polymer flooding implementation and current results.
Comprehensive Approach to Development of Prirazlomnoye Oil Field
Authors: Koloda Alexey , Morozov Oleg , Andriyanov Maksim , Kuntsevich Vitaly , Mukhametshin Ilkam , Galimzyanov Artem , Nukhaev Marat
Published: October 2018

Methods of field development of the Arctic shelf significantly different from oil land fields. The key features of the shelf fields are high costs and limited space to place the equipment. The field devepment plan should ensure high recovery factors with the relatively small number of production wells within the short period of time. The main factor to achieve the planned oil recovery factor is implementation of new technologies and approaches in the advanced well completion, well stimulation, and the use of full field reservoir model to take the best effective decisions in the part of the existing and project wells focused to increase the technological and economic efficiency of the project.

This work is devoted to the comprehensive approach to field development based on hydrodynamic and tracer studies, generalization of field-geological information and geological and hydrodynamic stimulation.
Improving Hydraulic Fracturing Fluids Through Dual Polymer Technology
Authors: Almubarak Tariq , Ng Jun Hong , Sokhanvarian Khatere , AlKhaldi Mohammed , Nasr-El-Din Hisham
Published: October 2018

As exploration for oil and gas continues, it becomes necessary to produce from formations that are deeper, have low permeability, and higher temperature. Conventionally, guar and its derivatives have been successfully utilized as hydraulic fracturing fluids. However, they require higher polymer loading to withstand the high-temperature environments. This leads to an increase in mixing time and additive requirements. Most importantly, they do not break completely and generate residual polymer fragments that can plug the formation and reduce fracture conductivity significantly.

In this work, a new hybrid dual polymer hydraulic fracturing fluid is developed for high-temperature applications. The fluid consists of a guar derivative and a polyacrylamide-based synthetic polymer. Compared to conventional fracturing fluids, this new system is easily hydrated, requires fewer additives, can be mixed on the fly, and is capable of maintaining excellent rheological performance at low polymer loadings.

The polymer mixture solutions were prepared at concentrations ranging from 20 to 40 lb/1,000 gal at a ratio of 2:1, 1:1, and 1:2. The fluids were crosslinked with a metallic crosslinker and broken with an oxidizer at 300-350°F. Testing focused on crosslinker to polymer ratio analysis to effectively lower loading while maintaining sufficient performance to carry proppant at these harsh conditions. HP/HT rheometer was used to measure viscosity and elastic modulus. HP/HT see-through cell was utilized for proppant settling.

Results indicate that the dual polymer fracturing fluid is able to generate stable viscosity at 300-350°F and 100 s−1. Results show that the dual polymer fluid can generate higher viscosity compared to the individual single polymer system. Also, properly understanding and tuning the crosslinker to polymer ratio generates excellent performance even at 20 lb/1,000 gal. The two polymers form a shared crosslinking network that improves proppant carrying capacity at lower polymer loadings and high temperatures. It also demonstrates a clean and controlled break performance with an oxidizer.

The major benefit of using a mixed polymer system is to reduce polymer loading at harsher conditions. Lower loading is highly desirable because it reduces material cost, eases field operation and lowers damage to the fracture face, proppant pack and formation.
Inhibition of Gas Channeling by CO2 Foam in Ultra-high Watercut Reservoir: Experimental Investigation Using NMR
Authors: Du Qingjun , Shi Lina , Hou Jian , Ji Yunkai , Zhou Kang
Published: October 2018

The oil recovery is improved by CO2 huff and puff in the ultra-high watercut reservoir, but gas channeling is very easy to occur. In this paper, the mechanism of increasing driving pressure and inhibiting gas channeling by CO2 foam puff-and-huff in ultra-high watercut reservoir was studied by nuclear magnetic resonance (NMR).

The experimental equipment is a visualization experiment system using nuclear magnetic resonance for oil and gas displacement (the magnetic field intensity: 0.3±0.05T). The influence of CO2/water ratio, permeability and displacement velocity on displacement pressure was carried out. The water saturation was determined on the basis of T2 spectrum, and the water distribution image during the experiments were obtained using imaging software. The ratio of displacement pressure difference between the CO2 foam flooding and water flooding at the same injection velocity is defined as resistance factor. The correlation between the resistance factor of CO2 foam and water saturation was established. The experimental results show that with the increase of injected CO2 foam volume, the water saturation decreased gradually, but the resistance factor changed little. After the injection volume reaches 0.5PV, the water saturation is reduced to about 0.62, the resistance factor increases rapidly, thus the water saturation defined as rising pressure water saturation. After the injection volume reaches 5.0PV, the water saturation is reduced to about 0.4, the resistance factor becomes stable. It is shown that the lower the permeability is, the greater the rising pressure water saturation, the smaller the resistance factor. When the CO2/water ratio is low, the foam is at low-quality state, the resistance factor is mainly controlled by the gas flow velocity; when the CO2/water ratio is high, the foam is at high-quality state, the resistance factor is mainly controlled by the water flow velocity; overall, the resistance factor firstly increased and then decreased as the CO2/water ratio increased. The corresponding CO2/water ratio is the optimal value when the resistance factor is maximum. The results helps to further analyze the mechanism of CO2 foam plugging and gas channeling inhibition.
Evolving Proppant Supply and Demand: The Implications on the Hydraulic Fracturing Industry
Authors: Olmen Brian D. , Anschutz Donald A. , Brannon Harold D. , Stribling Katherine M.
Published: October 2018

Flashback 10 years ago to 2008: the North American hydraulic fracturing industry utilized a then record breaking 21.41 Billion pounds and experienced exponential growth year-over-year (excluding 2015 and 2016). Prior to 2008, proppant demand grew at a relatively modest pace and overwhelmingly consisted of 20/40 mesh high quality natural sands and synthetic proppants. Fundamental changes in drilling and completion practices has given rise to a significant increase in the application of smaller mesh proppants, most notably 40/70, 30/50 and various forms of what is generically referred to as 100 mesh sand (i.e., sands that are predominantly smaller than 70 mesh) in natural gas and liquid applications. Proppant demand has now soared, increasing significantly as a result of the new high-intensity completions practices in horizontal wells. In 2018, an estimated 200 Billion pounds will be used for the first time in history (or 10 times that used in 2008).

The proppant supply industry responded well to the increased demand in the past decade, but the industry is increasingly concerned about future supply limitations and the potential impact on completion practices subject to high volume, quality and mesh size availability.

This paper summarizes the historical supply of proppant by type and source, and the driver for each proppant type based on the authors’ current and prior research. The paper will further clarify the basics of proppant by type and size (e.g., what is 100 mesh?) and will address some of the challenges that both the proppant supplier and end-user may face subject to current or desired completion practices. Key observations will be: 1) Potential limitations in the amount of proppant size and type, 2) The impact that specific proppant shortages may have on both supplier and end-user, and 3) Risk factors the proppant supply base may experience subject to future changes in completion design.

The objective of this effort is to encourage the need to study alternative completion designs subject to proppant availability. It is specifically not the intent of this paper to propose one form of completion practice or proppant type over the other.
Determining Gravel Pack Fluidization Velocity
Authors: Bhowmick Ankit , Amritkar Amit , Ehlig-Economides Christine
Published: October 2018

In a gravel pack completion, non-uniform reservoir inflow with a very high velocity can fluidize the gravel and/or erode the sand screen. The gravel pack screen is equipped with a basepipe with a pattern of holes through which fluid must pass after flowing through the gravel pack and screen. In a cased hole completion, fluid reaches the pack through a pattern of perforation tunnels opening into the gravel pack. The result is a complex flow pattern inside the pack involving both vertical and annular flow in addition to the expected radial flow. Previous studies have addressed the risks of fluidizing the gravel pack in high flow rate deepwater wells and have quantified a critical velocity above which fluidization is at risk. However, no formal mathematical model has justified the value, and details of the failure mechanism are lacking. This paper presents a Computational Fluid Dynamics (CFD) model that captures the complex flow dynamics within a cased hole gravel pack completion.

An ANSYS-FLUENT simulator was used to create a CFD model that simulated fluid flow through a gravel pack in conjunction with full particle motion phenomena. The Euler-Euler option treated each of two phases (flowing hydrocarbon and the gravel) as a continuum and enabled replication of gravel pack dynamics under producing conditions. Using well casing, screen, and basepipe geometries based on an actual field case from a conventional deepwater Gulf of Mexico well completion, the model provided visualizations of the nature of fluid flow through a gravel pack and captured destabilization (aka fluidizing) of gravel in a cased hole gravel pack completion.

The CFD model replicated the velocity changes projected by Wong for cased hole gravel pack completions. Fluidization tendencies and estimation of the minimum fluidization velocity in a gravel pack cased hole completion were determined. Sensitivities to flow rate, perforation density, base pipe geometry, and packing efficiency were evaluated. The model illustrated that at sufficiently high flow rates for certain gravel pack configurations, alignment of a basepipe and perforation holes can produce a jetting effect that could cause screen erosion. The model also revealed how the jetting effect could be suppressed.

This work underscores the importance of the gravel pack reserve height and packing efficiency. The fluidization velocity depends on gravel pack parameters that can guide the completion design. The model developed for this work enables testing whether a completion strategy is conservative enough to maintain the integrity of the pack. With aid of this model this study will be useful in designing gravel pack completions in ultra-high rate wells.
Exploration Portfolio Optimization for Increase of Investment Effectiveness
Authors: Zhukov Vladislav , Pogrebnyuk Sergey , Gazaliev Rinat , Bogdanovich Elena
Published: October 2018

Portfolio analysis is a tool to optimize investments, which is successfully used in various companies. While the principles and approaches of portfolio analysis have been known for a long time, examples of its application in the oil industry are limited. Exploration projects are often characterized by a low level of knowledge and a high degree of uncertainty of reservoir characteristics which determines the possibility of using portfolio analysis approaches in order to further select the optimal set of projects. It is important to understand that results of the analysis create the basis for the Company's development scenarios and balanced diversification of portfolio risks but they are not the final outcome of the work. The resulting scenarios are analyzed and corrected with a view to include particular projects in the regions of presence important for the Company or those projects than need to be implemented on a mandatory basis. Similarly, projects that are attractive by results of the scoring but not included in the current portfolio version can be added to the final set. This paper reviews some approaches based on portfolio analysis that can be applied to create a flexible basis for making decisions on the formation of a set of exploration projects. Forty five exploration projects in the perimeter of a number of Gazprom Neft subsidiaries are considered.
Capacity Assessment of CO2 Storage and Enhanced Oil Recovery in Residual Oil Zones
Authors: Chen Bailian , Pawar Rajesh
Published: October 2018

Residual oil zones (ROZs) are defined as those zones where oil is swept over geologic time period (natural flush) and exists at residual saturation. ROZs are increasingly being commercially exploited using CO2-enhanced oil recovery (EOR) (in Permian Basin). In this study, CO2 storage potential, long-term CO2 fate and oil recovery potential in ROZs are characterized. We use numerical simulations of CO2 injection with a reservoir model based on data from the Permian Basin. The changes of CO2 storage capacity and potential oil recovery with amount of CO2 injection are investigated. The effects of different well patterns (five-spot and line drive) and well spacing on fraction of CO2 retained in reservoir and cumulative oil production are also investigated. Furthermore, the effect of different CO2 injection modes, i.e., continuous CO2 injection and water-alternating-gas injection (WAG), on the CO2 storage and EOR potential are evaluated and compared. After the preliminary characterization of CO2 storage and EOR potential in ROZs, we next develop empirical models that can be used for estimating the CO2 storage capacity and oil production potential for different ROZs. A supervised machine learning algorithm, Multivariate Adaptive Regression Splines (MARS, (Jamali et al.)) is used for developing the empirical models.

Results show that CO2 retention efficiency and oil recovery vary non-linearly with amount of CO2 injected. It is observed that long-term CO2 fate is a function of CO2 injection amount and significant fraction of reservoir CO2 resides in hydrocarbon phase. Five-spot well pattern results in more oil production and larger amount of CO2 retained in reservoir than line-drive well pattern. During the investigation of well spacing, we observe that less number of wells actually results in higher CO2 retention and oil recovery, and less number of wells can also result in less probability of wellbore leakage. In comparison of WAG and continuous CO2 injection modes, it is observed that WAG injection has higher fraction of injected CO2 retained in reservoir, but with slightly lower cumulative oil production. In the study of empirical models for the capacity assessment of CO2 storage and EOR, results show that MARS can generate high-fidelity empirical models that can be used to predict the cumulative CO2 storage capacity and cumulative oil production for different ROZs.
Existence and Prediction of Severe Slugging in Toe-Down Horizontal Wells
Authors: Nair Jayanth , Pereyra Eduardo , Sarica Cem
Published: October 2018

Severe slugging is an important flow assurance issue, typically observed in offshore pipeline-riser systems. The consequences of severe slugging include flooding of downstream production facilities and an overall decrease in productivity. It had been previously thought that severe slugging would be limited to systems with a downward inclined pipeline and vertical, catenary or lazy-S shaped riser. This paper presents the results of an experimental and modeling study, which demonstrates the existence of severe slugging in systems with upward inclined lateral flow paths such as a toe-down well.

The severe slugging phenomena described in this paper was observed in a large scale experimental facility constructed for the purpose of studying flow behavior in horizontal wells. The facility enabled the study of the effect of the completion parameters like end of tubing location and the presence of a packer. Various gas and liquid rates were tested in the facility, and slug flow was the dominant flow pattern in the lateral section. The facility was also designed to test gas lift performance in horizontal wells. Therefore, the effect of gas lift on the severe slugging phenomenon was also studied.

Based on the experimental observations, two severe slugging prediction models were developed. The first was a transient model based on the Balino et al. (2010) model. The second was a single point criterion based on the Bøe (1981) criterion. The constitutive equations and modeling results are also presented in this paper.
Contribution of Artificial Intelligence and Machine Learning in U.S. DOE's Efforts During the Aftermath of Deepwater Horizon
Authors: Mohaghegh S. D.
Published: October 2018

Petroleum Engineering and Analytics Research Laboratory at West Virginia University (PEARL) played a key role in estimating the amount of oil being discharged into the Gulf of Mexico during the Deepwater Horizon disaster in 2010. PEARL's calculation of the amount of oil that was being discharges into the Gulf of Mexico were based on the Smart Proxy technology. Smart Proxy is a unique an innovative implementation of Artificial Intelligence and Machine Learning to develop fast and accurate proxy models of high fidelity numerical simulations that do not compromise the complex physics and the high resolution of the original numerical simulation models. Smart Proxy modeling was implemented by many of PEARL's scholars for their Ph.D. dissertations. Execution of the Smart Proxy models takes from fractions of a second to few minutes on a PC workstation (laptop) to accurately replicate detail results of high fidelity numerical simulation models that take hours or days to run on High Performance Computational facilities (HPC - clusters of large number of CPUs or GPUs).

As a subcontractor to the U.S. Department of Energy, National Energy Technology Laboratory (NETL), PEARL was asked to join a team of scientists and engineers from across the United States from multiple DOE national Labs in order to start an effort to estimate the amount of oil that was being discharged in the Gulf of Mexico. Since the initial BP's estimate of 1,000 barrels per day seemed an under-estimation (this estimate was later increased to 5,000 barrels per day after the initial estimate were challenged by the U.S. government), the Obama administration asked the secretary of Energy (the Noble Laureate, Steven Chu) to set up a team for providing a realistic estimate of the oil discharge rate into the GOM.

This article presents a summary the efforts by PEARL in estimating the oil discharge rate into the GOM during the Deepwater Horizon disaster. PEARL's use of Smart Proxy modeling of numerical reservoir simulation models coupled with detail numerical flow in pipe and network models allowed the team to generate millions of scenarios in order to exhaustively examine and quantify the uncertainties associated with all that was unknown and were being estimated at the time of analyses.

The final estimate of the oil discharge rate into the GOM calculated by PEARL proved to be highly accurate once the well was contained and the flow was actually measure providing a valuable use-case of the application of the application of Artificial Intelligence and Machine Learning in the upstream oil and gas industry.
Optimization of Fortified Section Length in HIPPS System
Authors: Kapadia Kashyap , Rodrigues Neil , Hayes Justin , Juzswik Jade , Kapoor Yogesh
Published: October 2018

In the recent era of low commodity prices, the offshore oil & gas industry has focused on economic tie-backs rather than standalone projects to exploit potentially stranded reserves in the Gulf of Mexico. High pressure tie-backs to existing infrastructure may be lucrative, but they are often challenging with respect to pressure & safety ratings.

A high integrity pressure protection system (HIPPS) can be used to safely contain pressures in a subsea flowline system when the shut-in tubing pressure (SITP) of a well exceeds the maximum allowable operating pressure (MAOP) of the tieback. As stated in API Standard 17O, a HIPPS system should be designed with highly responsive control systems, fast acting safety valves, and fortified sections of pipe known as "burst free zones." The burst free zone is designed to have a higher MAOP than the rest of the flowline system. Optimizing the length of this zone can be achieved by accurately determining both the SITP and the time it takes for the system to reach the maximum SITP. These two key parameters are dictated by how the reservoir pressure responds during shut-in.

With the availability of fast-transient multiphase flow simulation, it is possible to simulate the SITP and optimize the fortified section length. However, currently-available thermodynamic multiphase flow simulators do not provide an option to simulate near-wellbore reservoir phenomena. These software packages only simulate the shut-in of the well as an instantaneous pressure buildup, which is often very conservative for HIPPS and predicts fortified sections lengths that are longer than necessary.

To simulate appropriate pressure buildup from the reservoir, a multiphase transient package is coupled with a reservoir simulation software that accounts for reservoir response and near-wellbore behavior. This model more accurately simulates the time required to reach the SITP, thus optimizing the selection of fortified section lengths. Additionally, reservoir and production factors that influence the fortified section length were also studied. One of the main influencing factors identified was fluid GOR. This is because a higher GOR fluid is more compressible; therefore, the time it takes to reach the maximum SITP increases, ultimately decreasing the required fortified section length. This paper will discuss how to apply known reservoir pressure responses to a coupled reservoir and multiphase transient simulator tieback scheme to optimize fortified section lengths when a HIPPS system is applied. It will also analyze the influence that production and reservoir characteristics have on the fortified section length and discuss how to optimize that length.
Integrated Optimization as a Way to Increase the Project Value on the Example of the Achimov Deposits Development Evaluation
Authors: Nishonov Timur , Mullagaliev Almaz
Published: October 2018

Integrated optimization, as an approach, is based on multivariate hydrodynamic modeling, the application of probabilistic methods, the application of game theory to the search for sustainable solutions, the identification of optimization problems at all stages of project evaluation. The application of game theory approaches allows us to formalize the problems associated with optimization at the stage of geological evaluation, selecting a rational geological program. The application of the probabilistic approach makes it possible to increase the cost by reducing the risk capital, determining rational exit conditions from the project and applying the technological limit. This approach is applicable for different levels of complexity of models, because it is a combination of integrated models and iterative stages, which ultimately allows you to determine the global optimal solutions. Within the framework of the approach, problems such as constructing a probabilistic hydrodynamic model, taking into account the technological limit when choosing a well design, determining rational conditions for exiting a project, interrelating an exploration program and selecting a development system are solved for the first time. The paper describes the approach and methodology of integrated optimization, which allows to increase the value of projects. The approach is considered on the example of analysis and evaluation of projects for the development of a number of deposits with Achimov deposits.
Improved Understanding of Acid Wormholing in Carbonate Reservoirs Through Laboratory Experiments and Field Measurements
Authors: Burton Robert C. , Nozaki Manabu , Zwarich Nola R. , Furui Kenji
Published: October 2018

A comprehensive study on wormholing has been conducted to improve the understanding of matrix acidizing in carbonate reservoirs. This work is a continuation of previous work (Furui et al. 2012a, 2012b). An analysis of additional experimental results as well as field measurements is provided to reinforce and extend the wormhole penetration model and productivity benefits provided by Furui et al. (2012b).

A series of small block tests and one large block test under geomechanical stresses has been conducted to characterize wormholing in outcrop chalk samples. In addition, field data including acid pumping data as well as post-stimulation pressure falloff data has been collected and analyzed to evaluate stimulation effectiveness. Pressure buildup data from stimulated wells has also been analyzed to evaluate the sustainability of the acid induced skin benefits. Production logging data has been used to investigate whether created wormhole networks have remained stable or have collapsed under production stresses. To statistically analyze the data more comprehensively, the new data was also compared to the data from other field data available in the literature.

The following conclusions are drawn from an analysis of the laboratory data and field data: 1) a skin value of −4 is achievable in carbonate reservoirs by matrix acidizing, 2) the negative acid skin is relatively stable under production stresses, 3) the wormhole penetration model is proven to successfully simulate matrix acidizing processes in both laboratory scale and field scale work, 4) the small and large block laboratory tests re-confirmed wormholing efficiency which was discussed as a scale effect in previous studies, 5) an understanding of the possible range of wormhole penetration has allowed us to improve field acid treatments and reduce the risk of connecting to water.

This comprehensive study includes acid linear core flooding tests, small block tests, large block tests and field measurements to thoroughly analyze acid wormholing in carbonate rock. The database can be very useful information for understanding, benchmarking and optimizing future completion/stimulation design.
The Analysis of Critically Stressed Fractures with Reconstruction of Tectonic Stresses for Ranging the Area by Production Rates via Example of Riphean Carbonate Fractured Reservoir
Authors: Zhigulskiy Svetlana , Rotaru Anna , Kurbanov Vasif , Zadvornov Dmitriy , Maximov Danil , Eremeev Alexandr , Rijikov Pavel
Published: October 2018

In this study, the geomechanical analysis of the Riphean fractured carbonate resevior of East Siberia is provided. The research of fissuring and its further deformation mechanism is necessary both for drilling risk assessment (prediction of fluid losses zones due to intensive natural fracturing) and for ranging of perspective drilling zone in terms of its productivity.

For described reservoir it is supposed, that natural fractures are the main driver of wells productivity. Reservoir rock is characterized by low average matrix porosity (lower than 3%), which does not influence wells productivity.

As for fractures system, according to production logging (spectral noise survey), wide-bend acoustic logging (Stoneley wave interpretation), formation imager (resistivity and acoustic), drilling data (fluid losses) it was concluded that not all fractures are permeable. Comparison of fracture characteristics from different surveys shows that working intervals according to SNL mismatch with permeable intervals from Stoneley wave interpretation and do not fit with maximum fracture density intervals from formation imager.

The analysis showed mismatching of productive intervals from Stoneley wave interpretation and SNL results and absence of direct correlation between fracturing and productive intervals for both methods. This can be explained by low amount of working fractures: less than the half of horizontal section works. Moreover, the risk of drilling throught "dry" zone, where no permeable fractures exist, was confirmed by several unsuccessfull wells.

On the base of geological and morphological fracture features such as intensity, dip angle, orientation there is no ability to subdivide dry and permeable fractures. That is why for better reservoir understanding the mechanism of fracture occurance, development and activation is analysed.

Application of geomechanical modeling for fractures assessment and subsequent forecast of productive zones is rather nontrivial and complex task that required abandoning the traditional approach of creating a geomechanical model in which the main emphasis is on a wellbore stability calculation.
Formation of Complex Fracture Networks in the Wolfcamp Shale: Calibrating Model Predictions with Core Measurements from the Hydraulic Fracturing Test Site
Authors: Shrivastava Kaustubh , Hwang Jongsoo , Sharma Mukul
Published: October 2018

Natural fractures are a crucial factor in determining fracture and well spacing in horizontal wells. Their attributes affect the created fracture network and thereby the well producivity and EUR. However, information about the properties of natural fractures is seldom available. In this study, we used a detailed core description from the Hydraulic Fracture Test Site (HFTS), funded by the DOE and an industry consortium, to obtain in-situ natural fracture distribution data. The data was used as input into a hydraulic fracturing simulator to model fracture growth in the presence of natural fractures. The results obtained were then compared with field observations of cores taken from a slant infill well drilled into the hydraulically fractured rock.

The core taken from the slant well located adjacent to the hydraulically fractured well is used to characterize the natural fractures (density and orientation). A two-dimensional discrete fracture network (DFN) is generated based on the core description. Nine coring operations are simulated on the created DFN to generate synthetic core descriptions. Attributes (length and density) of natural fractures are calibrated to match the results obtained from simulated coring operations with real core data. Multi-stage hydraulic fracturing simulations are performed using the calibrated DFN, and the results are presented in this paper.

The core analysis identified three different types of fractures: hydraulic fractures, intact natural fractures, and natural fractures activated by hydraulic fractures. The density and orientations obtained from the core description provide valuable insights on the complex fracture growth behavior. The number of created fractures (propped and unpropped) far exceeds the number of perforations. This indicates the formation of complex fracture networks likely caused by the interaction of the hydraulic fracture with natural fractures and bed boundaries during propagation. A heel-side bias of fluid and proppant distribution within a stage was also observed. The effect of inter-stage stress shadowing on fracture growth could also be inferred.
Application of the Inversion Stress Model for Estimating the Parameters of Fault Tectonics
Authors: Sidelnik Angelina , Lukin Sergey
Published: October 2018

The purpose of this work is to determine the parameters of fault tectonics by constructing an inversion stresses model with a weak quality of the seismic survey, as well as identification of compression and extension sectors by the structural-geomorphological method (SGM) in subsalt productive sediments.

The tasks for achieving the goal of the paper: analysis of the quality of available information about fractures within the studied oil deposit, calculation of the inversion stress model, identification of the compression and extension sectors according to the SGM.

Reconstruction of stress fields in conjunction with geomechanical analysis is a tool for studying the patterns of fracture development in rocks and tectonic evolution of the region.

Determination of fault parameters and allocation of zones of intensive fracturing allows optimizing trajectories when drilling horizontal and inclined wells, assuming intervals of potential drilling complications, predicting risks during fracturing operations, and qualitatively evaluating the reservoir properties by deformation sectors.

As inputs to the calculation of the inversion stress model, disjunctive dislocations that are confidently identified by seismic data and records of an electrical microimager appear. Based on information about the spatial location of the actual cracks and faults, the orientation of the tectonic force contributing to the formation of this fault system is calculated.

The result of the construction of the inversion stress model are maps of displacement and deformation fields. Analysis of these maps in zones with different values of displacements and deformations allows to single out low-amplitude disjunctive dislocations, which are ambiguously determined when interpreting seismic survey. The calculation results are calibrated for microimager data, special core studies, drilling data.

The initial data for the structural-geomorphological method are topographic maps, space images and digital surface models.

As a result of applying the structural-geomorphological method, it is possible to reconstruct the orientation of the axes of compression and stretching of neotectonic stresses in the horizontal plane, determine the direction of the shear displacement along the fault (right or left shear), reveal additional stressed conditions in the formation of the fault, and identify the compression and extension sectors.

Approbation of these methods was carried out at the oil field of the Leno-Tunguska oil and gas province of the Siberian platform.

Based on the results of the calculation, a small-scale map of fault tectonics was compiled within the studied oil deposit. Further use of this map is planned as a basis for calculating a 3D geomechanical model and selecting a development system. In the process of obtaining new information (data on core research, microimages, drilling data), a map of fault tectonics will be modified.
Real-Time 3D Computer Vision Shape Analysis of Cuttings and Cavings
Authors: Han Runqi , Ashok Pradeepkumar , Pryor Mitchell , van Oort Eric
Published: October 2018

Excessive cuttings and cavings accumulation due to poor hole cleaning and borehole instability can cause costly stuck pipe incidents. Currently, there is no surface instrument to monitor cuttings volume and detect cavings in real-time. An automated 3D real-time computer vision monitoring system can quantify cuttings return volume, detect cavings presence, and analyze cavings shape. This makes pro-active prevention and mitigation of non-productive time (NPT) caused by poor hole cleaning and wellbore instability possible.

In this paper, we present a real-time computer vision system to measure cuttings properties and detect cavings. The proposed design consists of a 2D high-resolution camera and a 3D profile laser scanner, which collect point cloud/depth data of cuttings/cavings after passing the shale shaker. We apply cutting-edge computer vision algorithms and feature recognition techniques to quantify cuttings volume, detect cavings, and characterize cavings shape. The angularity, flatness, and other geometrical features of cuttings/cavings can be determined from the point cloud 3D data.

A prototype computer vision system was constructed and tested in the lab and test yard to evaluate the system capability to measure cuttings/cavings properties. In a controlled laboratory environment, a sensing algorithm was designed and tested in the presence of drilling fluid. To improve measurement accuracy, both artificial and field cavings were used to simulate realistic scenarios and train a data pool. The system was then validated in a test yard shale shaker testing facility. The accuracy, repeatability, and robustness of the sensors were evaluated against external lighting variances, dust, humidity, etc. The proposed automated cuttings/cavings monitoring system can identify cavings and analyze shape characteristics. By diagnosing potential hazards, the system warns the driller on adverse wellbore conditions and the likelihood of stuck pipe events. This paper proposes and demonstrates a novel 3D depth-sensing system to measure cuttings volume, identify abnormal cavings, and analyze shape. This state-of-art, non-intrusive system evaluates cuttings/cavings quantitatively and delivers algorithms that automate downhole condition monitoring to reduce drilling-related NPT in the field.