bluuebunny/crossref_metadata_2025 huggingface dataset:
Design and Development of Relational Geospatial Database Aimed at Gathering and Systematization of Wide Range of Geological and Geophysical Data
Authors: Kolmakov Aleksandr , Kilyakov Aleksey
Published: October 2018

The work represents the results of design and development of object-relational geospatial database which combines the diversity of geological and geophysical data and enables to represent the data as an object of linear algebra for further analysis by means of machine learning algorithms.
Evolution of Integrated Models From Simplified Approach to Complex Reservoir - Well - Surface Network Representation at Different Stages of Gas Condensate Field Lifecycle
Authors: Voznyuk Alexander , Gataullin Timur , Poushev Andrey
Published: October 2018

The tendency of recent years in the sphere of modeling oil and gas fields and the processes of oil and gas fields' development is an increase of complication of models, revision and abandonment of a number of simplifications, which were necessary earlier due to the limited computing and time resources available to engineers.

This tendency makes more widespread such approach as accounting for the performance and optimization of surface gathering systems becomes a critical task in the case of gas, gas condensate fields, and also - light oil fields. Given the apparent growth in the interest of oil and gas companies in such assets, the popularity of integrated modeling in the industry as a whole is extremely high.

The problem with this technology is that the integrated simulation models are complex in the creation, they require more knowledge from the engineers involved in the project in the related field of activity (the reservoir engineer should have an idea of the principles of operation and methods of managing the surface network, production engineer should understand the physical basis of the work not only of the reservoir, but also of its simulation model, etc.).

Both the network model and the reservoir model can be performed in different variants in terms of the complexity and accuracy of the transfer of the boundary conditions and taking into account the necessary physical effects. This article offers a comparative analysis and possible applications of different types of models, and also describes a number of additional tools that help to eliminate some typical problems of this class of tasks.
The Individual Certified Flowmeter of Liquid in the Well
Authors: Ulyanov Sergey , Sagyndykov Rustam , Davydov Denis , Dolinyuk Valeria , Gilaev Gennady , Totanov Alexander , Nosov Sergey , Ilyin Alexey
Published: October 2018

Liquid and gas production rates assessment is crucial while well operation. Based on the measured data obtained the evaluation of downhole pumping equipment condition, pump productivity and reservoir capability is performed, measures for improving pumping equipment operation and its rehabilitation are designed, well operation modes are defined.

Traditional well metering stations used by JSC “Samaraneftegas" are not only the basic tool to define the volumes of the oil extracted from oil wells but are also one of the costly spheres in oil production. At present, the applied metering stations, compared to old-time automated group metering stations, require either substantiated upgrading aimed at well smart operation and simplification of their structure and higher accuracy in metering, or the optimization of specific costs for the rent of expensive mobile metering stations. [9]

The promising approach to this solution is a budget set of measurements, based on the system of thermal pressure metering that within the frames of the issue considered is transformed into the process of instrumental on-line fluid rate metering. The paper considers the conceptual process and structural changes in geometry and coating of the existing flowmeters that enables us to consider this type of oil-field equipment as a certified metering device to replace the classic flowmeter stations. Taking into consideration the experience of thermal pressure metering system on the wells and the failure of its weakest part which is the communication link, the wireless channel of communication was made transmitting all signals by means of infrasound.

The solution allows introducing the device with no additional costly equipment and is a classical system of measurements with the firmware sensor of measurement of flow rate installed above the electric submersible pump (ESP). Tlike any other oil well provided with the standard unit of electric submersible pump, the complex of thermal pressure metering has the control station and the land-based system of thermal pressure metering. The process of measurement and fixing of parameters is given in fig. 2. [11]

The present design solution also gives a chance to improve the energy efficiency in oil production industry, to reduce the number of damages and service of submersible oil-pumping equipment, to optimize the system of reagent dosing and will bring the significant economic effect without high costs for production.
Single Flowline Tiebacks: Flow Assurance Considerations From Appraisal to Operations
Authors: Monge Juan I. , Bukkaraju Sampath K. , Osorio Nelson F.
Published: October 2018

In addition to the recent downturn in oil price, as tiebacks get deeper, longer and originate from more remote areas, interest in making single flowline tiebacks (SFTs) viable development options continues to grow. SFTs provide a means for smaller operators with marginal projects and large international operators with stranded assets to move projects from concept to producing assets. The main challenges in making SFTs viable are: Development and implementation of mitigation and remediation strategies for addressing the typical flow assurance challenges encountered in deep-water.Development of operational strategies considering the processing and liquid handling capacities of the existing tieback host.

By more clearly understanding the operating conditions from subsurface to surface and systematically addressing each of the field's challenges with novel operating techniques, enhanced facilities and/or chemicals, SFTs have gone from once simply a conceptual idea, to a valid development alternative. The focus of this paper is to apply findings and lessons learned from various SFT projects, ranging from concept selection to decommissioning, to highlight various considerations. It is the hope and intent that by highlighting these considerations we, as an industry, can continue to mature SFTs. This maturation will then be able to provide an alternative development option to make certain projects economically viable, while not making them unfeasible, difficult and unsafe to operate.
Unorthodox Fluids for Unconventional Completions: Maximizing Production and Avoiding Pitfalls
Authors: Carman Paul , Li Chunlou , Wheeler Richard
Published: October 2018

The burgeoning development of shale and unconventional formations in the face of a limited supply of guar, the primary gellant for fracturing fluids, created a demand for an alternative fluid. The new fluid, a modified friction reducer, capable of generating high viscosity with increased loadings and containing unique chemistry to facilitate breaking of the fluid provides a cost effective way of proppant transport. Since 2011, it has been used together with different types of proppant to treat various formations in the United States, both conventional and unconventional. Even with a wide technological acceptance, this fluid is not a solution for all situations. This study presents the application results, positive and negative, which are equally important for the continuous improvement of fracturing stimulation.

Mining an in-house treatment database, this study collects treatment designs and operation parameters for all fracturing jobs performed in the following five major unconventional plays: Bakken/Threeforks, Eagle Ford, Marcellus, Utica and Wolfcamp. By using the publicly available FracFocus database, offset wells nearby the wells of interest were identified and their basic treatment information was collected, analyzed and normalized based on geography. Production performance metrics such as peak production and cumulative production in near and long term were used to evaluate the production performance of wells included.

This study shows that this technology has been successfully deployed in temperatures up to 300°F. Many wells treated in the Bakken have measured depths (MD) over 20,000 ft and true vertical depths (TVD) over 11,000 ft. Proppant with various mesh sizes from 100 to 20/40 are carried by this type of fracturing fluid. Due to the complex nature of unconventional formations and a long list of designing and operating parameters, it demonstrates outstanding performance in certain cases and may show why it has unfavorable results in others.

In comparison to other studies, this evaluation incorporates the near and long term results. The detailed analysis of this fracturing fluid technology and how its production performance sheds light on some questions that completion engineers are longing to answer: In which formation does this fluid have the best results and what types of formations should be avoided? What can be modified in job design to improve its performance?
Perfecting Operational Execution: The Journey to High Reliability in the Oilfield
Authors: Tower Patrick , Williams Austin , Sakievich Sam , Howdeshell Tony , Kearley Patrick , Motruk Lonny , McCullough Tony
Published: October 2018

High Reliability Organizations (HROs) are organizations with systems that maintain exceptionally low failure rates while operating in environments where the nature of the risk and complexity of serious incidents would be anticipated. HROs such as nuclear submarines, aircraft carriers, and the fire service have no fail missions because the costs of failure are extremely high. Applying the same systems and tools that created their passionate commitment to excellence that permeates every aspect of their operations, other industries can produce their own culture of high reliability where nearly perfect safety and service quality are the norm.

The aim of this paper is to illustrate how the principles, concepts, and processes of HROs, including Crew Resource Management (CRM), can optimize operational execution of a pressure pumping company through increased levels of safety and quality. The contemporary oilfield operating environment requires teams to be proactively aware of emerging threats and to trap errors or incidents to prevent them from escalating into significant incidents.

The paper includes the following themes: A literature review of the principles and concepts of traditional and established HROs from other industries;The process and systems to operationalize HRO principles and concepts within the energy industry; andTwo case studies demonstrating how HRO principles and concepts allow teams in the oilfield to reduce system failures and to notice, confront, resolve, and learn from unforeseen problems and failures when they do occur.
Evaluating Well Casing Integrity with Non-Invasive Electromagnetic Methods
Authors: MacLennan Kristopher , Nieuwenhuis Greg , Wilt Michael , Um Evan , Pendleton Joseph M.
Published: October 2018

Casing integrity is a major issue for thousands of older oil and water wells. Damage to well casings may occur for multiple reasons, including corrosive wellbore fluids, mechanical failures, or external forces, and can lead to impaired production and environmental risks. We propose a rapid, non-invasive electromagnetic (EM) method for diagnostic testing of casing integrity. The well casing is energized by connecting an electrical current source at low frequency to the wellhead. Current flows down the casing and out into the formation at a rate defined by the length of the casing, the casing conductance, and the formation resistivity. Damaged casing has a reduced conductance, and so the flow of current is altered, with an increased amount leaving the casing above the damaged segment. This affects the electric fields observed at the surface, a difference which can be measured with sufficiently sensitive electric field sensors. By comparing forward modeling results based on wellbore diagrams of intact casing with the observed fields, we can arrive at an estimate of whether or not the casing has been damaged. This paper describes the theory behind this method and validates the methodology through synthetic modeling. We also consider how the effects of various common oilfield scenarios may affect the success of the EM casing integrity evaluation method.
Utilizing Geomechanically Informed Completions to Reduce the Environmental Impact of Hydraulic Fracturing in Unconventional Reservoirs
Authors: Hildick Alice M. , Scott Ellen L.
Published: October 2018

Recently, the United States (US) oil and gas industry has dramatically increased its production, primarily due to technological advances in horizontal drilling and hydraulic fracturing. Current hydraulic fracturing practices require a significant amount of water. Section 9.2.1 of the API Recommended Practice (2015) states that of development activities including drilling and completion activites, hydraulic fracturing, typically results in the most significant water use. For context, hydraulic fracturing operations in 2000 used approximately 177,000 gallons of water per oil and gas well. According to USGS, hydraulic fracturing requirements increased to over four million gallons of water per oil well and 5.1 million gallons of water per gas well in 2014 (USGS, 2015). The Environmental Protection Agency's multiyear study found an increasing trend in water use per well attributed to growing numbers of wells drilled, with longer laterals and more stages completed (Dunn-Norman, et al., 2018).

Many US oil and gas companies’ annual reports and public communications currently feature sustainability and environmentally-responsible development strategies. However, opportunities to minimize negative environmental impact without affecting the value of a large-scale unconventional development is extremely difficult, particularly in the current low oil price market. Operators throughout the industry are developing water management facilities focused on safe, reliable and environmentally friendly water management practices. This paper discusses utilizing in-situ mechanical rock property data to optimize completion strategies, which can help reduce the negative impacts of hydraulic fracturing, while maintaining, and often increasing, production.
Stimulated Oil Reservoir Volume Estimation of Prominent US Tight Oil Formations
Authors: Panja Palash , Velasco Raul , Deo Milind
Published: October 2018

In this work, we estimate the Stimulated Original Oil In Place (SOOIP) of hydraulically fractured horizontal wells in prominent shale plays. This is done by compiling production data from hundreds of wells belonging to the Bakken, Niobrara, Wolfcamp, Eagle Ford, Bone Springs, and Woodford totaling over 2,500 wells. Additionally, we present probabilistic distributions of SOOIP with mean, standard deviation, P10, P50, and P90 estimates for each play.

To circumvent the challenge of data availability for each well, we use the findings of a previous study where all reservoir unknowns are grouped into two major parameters. One of these parameters, alpha, is a function of the stimulated reservoir volume, compressibility, and pressure drawdown, where the last two are unknowns. While alpha is determined with high confidence for each well, we account for the uncertainty of compressibility and drawdown values across wells by assuming a normal distribution for these parameters. Lastly, by incorporating 1 million Monte Carlo samplings and a Mersenne Twister random number generator we estimate SOOIP distributions for each play with varying degrees of confidence.

The final results show that the Niobrara and Bakken have the highest mean SOOIP values per well while the values for the Woodford and Bone Springs are the lowest among all six plays considered. Volumetric calculations using data from the literature qualitatively corroborate these findings. New insight on the stimulated volumes per well for prominent shale plays can be derived from these results as they correlate to horizontal well length, formation thickness, and hydraulic fracture half-lengths in each play.
Field Validation of a New BHA Model and Practical Case Studies in Unconventional Shale Plays, with a Framework for Automated Analysis for Operations Support
Authors: Wilson J. K.
Published: October 2018

A new three-dimensional drillstring model has been developed that determines the static and dynamic behavior of bottom hole assemblies (BHAs) in realistic wellbores. The analysis approach has been validated with field data, and shows a strong agreement between observed and calculated BHA behavior. Several case studies are presented that show the practical use and benefit of the advanced model for, among other applications, unconventional horizontal drilling. A framework is also provided to show how the model can be incorporated into automated engineering processes for operations support.

Validation tests were conducted using high-frequency down-hole data measured within a motor- assisted rotary-steerable BHA. The gathered data was used to verify the calculated mechanical loads, predicted lateral natural frequencies of the BHA, estimated directional performance of the down-hole assembly, as well as torsional resonance resulting from High-Frequency Torsional Oscillations (HFTO). Using the validated model, various analyses have been conducted for operators around the globe, in a multitude of different drilling environments, to aid in identifying drilling dysfunctions and optimizing BHA performance. Several case studies are presented that highlight the benefit of the modeling techniques in US unconventional shale plays as well as in the Canadian heavy-oil sands, with noticeable improvements in drilling efficiencies, tool design, and reduced non-productive time (NPT).

Results from the field tests show a strong correlation between measured and calculated bending moment values, as well as lateral natural frequencies of the BHA with an average of 3% error across all data sets. The primary source of error is thought to be borehole spiraling, which is quantified through analysis of the down-hole bending moment data. In addition, the model is shown to provide close estimates to actual directional performance of both steerable mud motor and Rotary-Steerable BHAs. However, the directional calculation-measurement comparison does reveal a need to incorporate an ROP-dependency within the directional prediction algorithms.

Nevertheless, even with these sources of discrepancy, the modeling approach provides a sensible prediction of the BHA's mechanical and dynamic behavior and, as shown through case studies, can be used as a planning tool for BHA design, an investigative tool for root-cause analysis, or potentially as a real-time optimization tool for avoiding harmful operating conditions.
Hydraulic Fracturing Design in Shale Formations Based on the Impact of Fracturing Additives on the Fluid Loss and Flowback
Authors: Al-Ameri Aymen , Gamadi Talal , Ispas Ion , Watson Marshall
Published: October 2018

Throughout fracturing treatment, millions of gallons of water are injected, but commonly less than 50% is recovered after stimulation. This study was constructed to evaluate the impact of the fracturing additives on the fluid flowback and fluid loss during hydraulic fracturing. Different pad fluids types were considered including; friction reducer fluid, friction reducer with a non-ionic surfactant fluid and 3 wt% HCl acid.

Flooding experiments were conducted for core samples from the Eagle Ford outcrop to measure the brine permeability, time of breakthrough and water relative permeability. The measurements were performed for intact samples and also after flooding the samples with the fracturing fluids. A simulation sector modeling for a hydraulically fractured vertical well in the shale formation was constructed to investigate the effect of the fracturing additives on the fluid flowback and fluid loss during hydraulic fracturing. A sensitivity analysis was considered to study the effect of the formation capillary pressure and reservoir pressure on the fluid flowback and fluid loss due to counter-current capillary imbibition.

The study results showed that the fluid saturation in the near fracture face shale matrix is highly reduced by the effect of the high capillary pressure. Therefore, the fluid had not flow back from the near fracture face matrix. Moreover, adding a non-ionic surfactant to the friction reducer pad fluid or using 3 wt% HCl increased the fluid loss during pumping and the fluid imbibition during shut-in, flowback, and production. Therefore, the dilute HCl acid and small well shut-in times are recommended when no flowback occurs from the near fracture face matrix due to low fluid saturation.

The fluid loss from the near fracture face region due to counter-current capillary imbibition reduced the effect of the fluid saturation on the gas production. However, the high fluid saturation and the polymer adsorption may cause water blocks. Thus, reducing the gas production or leading to a complete gas block.

For shales with moderate capillary pressure, a flowback from the near fracture face matrix has occurred. Hence, the friction reducer with a non-ionic surfactant fluid and 3 wt% HCl enhanced both of the fluid loss due to counter-current capillary imbibition and the fluid flowback. However, a non-ionic surfactant and long shut-in time are recommended for the hydraulic fracturing. Shales with low reservoir pressure had less fluid flowback and more fluid loss. To minimize the fluid loss during pumping and to overcome the water block problem, it is recommended to use a friction reducer fluid in the pad stage while injecting a non-ionic surfactant or dilute acid during the subsequent fracturing steps.
Integrating Propellant and Shaped Charges to Improve Frac Efficiency
Authors: Albert L.. , Nery N.. , Prapoo H.. , Dai P.. , Qu B.. , Jiang G.. , Kwok D..
Published: October 2018

Current perforating guns utilize shaped charges with high energy explosives (RDX, HMX, etc.) to shoot high velocity jets of metal in a direction that is perpendicular to the gun body (and casing), thus creating holes in casing and tunnels through cemented annulus and formation. The physics of shaped charge perforating (high velocity jet of metal penetrating casing and formation) results in a crushed zone of rock around the perforation tunnel. Rock crushing increases skin and lowers permeability in the near wellbore region, making formations more difficult to breakdown and increasing treating pressures. There have been many methods developed to overcome the perforation crushed zone and improve flow efficiency. These methods include underbalance, overbalance, propellants, charge orientation and reactive shaped charge liners.

Propellants (energetic materials with slower burn rates than explosives shaped charges) have been utilized in a number of methods to create a delayed pressure pulse to break-up the crushed zone around perforation tunnels. Propellants have been added as solid sleeves over guns, solid sticks ignited across open sets of perforations and propellant discs within gun bodies. With each of these techniques, propellant is located within the wellbore when it burns, thus the pressure pulse builds within the casing and then flows into perforation tunnels. As the pressure pulse moves into perforations, it can disrupt the tunnel crushed zone and create fractures. The net effect is lower skin and improved perforation efficiency. Unfortunately, by burning propellant within the casing, the efficiency of the pressure pulse is reduced.

To tackle the challenges above, a new method is proposed to place propellant in a molded cap that attaches to the face of individual shaped charges. This new method results in jets produced by shaped charges dragging the propellant material behind the high velocity jet as it penetrates casing, cement annulus and formation. As a result, most of the propellant burns sequentially within the perforation tunnel, thus delivering direct continuum pressure pulse to the perforating event. The propellant provides a secondary stream of energy, enlarging the perforation tunnel diameter, cleaning up the perforation tunnel and giving impetus to the shaped charge jet, resulting in deeper penetration. The result is very effective and efficient in disrupting crushed zones and creating fractures around the perforation tunnel.
Combining Decline Curve Analysis and Geostatistics to Forecast Gas Production in the Marcellus Shale
Authors: Xi Zhenke , Morgan Eugene
Published: October 2018

Traditionally, in order to estimate the production potential at a new, prospective field site via simulation or material balance, one needs to collect various forms of expensive field data and/or make assumptions about the nature of the formation at that site. Decline curve analysis would not be applicable in this scenario, as producing wells need to pre-exist in the target field. The objective of our work is to make first-order forecasts of production rates at prospective, undrilled sites using only production data from existing wells in the entire play. This is accomplished through co-kriging of decline curve parameter values, where the parameter values are obtained at each existing well by fitting an appropriate decline model to the production history. Co-kriging gives the best linear unbiased prediction of parameter values at undrilled locations, and also estimates uncertainty in those predictions. Thus, we can obtain production forecasts at P10, P50, and P90, as well as calculate EUR at those same levels, across the spatial domain of the play.

To demonstrate the proposed methodology, we used monthly gas flow rates and well locations from the Marcellus shale gas play in this research. Looking only at horizontal and directional wells, the gas production rates at each well were carefully filtered and screened. Also, we normalized the rates by perforation interval length. We kept only production histories of 24 months or longer in duration to ensure good decline curve fits. Ultimately, we were left with 5,637 production records. Here, we chose Duong’s decline model to represent production decline in this shale gas play, and fitting of this decline curve was accomplished through ordinary least square regression.

Interpolation was done by universal co-kriging with consideration to correlate the four parameters in Duongs’ model, which also showed a linear trend (the parameters show dependency on the x and y spatial coordinates). Kriging gave us the optimal decline curve coefficients at new locations (P50 curve), as well as the variance in these coefficient estimates (used to establish P10 and P90 curves). We were also able to map EUR across the study area. Finally, the co-kriging model was cross-validated with leave-one-out scheme, which showed significant but not unreasonable error in decline curve coefficient prediction.

We forecasted potential gas production in the study area using co-kriging. Heat maps of decline curve parameters as well as EUR were constructed to give operators a big picture of the production potential in the play. The methods proposed are easy to implement and do not require various expensive data like permeability, bottom hole pressure, etc., giving operators a risk-based analysis of prospective sites. We also made this analysis available to the public in a user-friendly web app.
Modified Arps Equation for Changing B-factor
Authors: Biseda Brent
Published: October 2018

SPEE Monograph 4 establishes recommended best practices for decline curve analysis of unconventional wells through the use of specialized diagnostic plots such as the square-root of time plot. These diagnostic plots are important for flow regime identification and selection of an appropriate b-factor for predicting a well’s EUR. However, in practice, because of familiarity with the Arps decline equation and its ease of use, typically a single b-factor is selected despite multi-fractured horizontal wellbores demonstrating changes in flow regime and consequently the b-factor. This paper introduces the Modified Arps Equation, an iterative formulation of the Arps equation. The Modified Arps Equation maintains use of the form of the original Arps equation with a few modifications to allow for a changing b-factor. These modifications allow a single equation to be used with a vectorized b-factor in order to model a well as it transitions from linear flow to boundary dominated flow and eventually back to pseudo-linear flow. This equation may be applied broadly across unconventionals where wells transition over years from linear flow to boundary dominated flow and later return to pseudo-linear flow as simulation data suggest.
A Novel Workflow for Fracture Reconstruction and Uncertainty Analysis for Unconventional Reservoir Development
Authors: Liang Baosheng , Du Song
Published: October 2018

Fracture networks present a critical influence on to better assess oil recovery and to optimize production of hydraulically fractured reservoirs. We established a novel workflow for fracture uncertainty analysis and prediction, in which multiple fracture pattern realizations are created from the geostatistical analysis. The original fracture networks were created using geomechanics tools. Then the fracture network is reconstrued for uncertainty analysis and history matching. For different realizations of the fracture distributions created in this workflow, we successfully maintain the continuity of the fractures, as well as the connections from the matrix to fractures. The generated grid can be further used for treatment simulation to determine fractures geometry, height growth and respected proppant transport in the induced fracture network.

In this paper, we also apply Embedded Discrete Fracture Model (EDFM) to capture the realistic geometry of fractures. Within the EDFM, each fracture plane is embedded inside the matrix grid and is discretized by the cell boundaries. We study a series of reservoir simulation realizations, in which the complex hydraulic fracture networks are created in the workflow. We investigate different fracture realizations in both planar and complex fracture configurations while maintaining the continuity within the fracture networks. This study also includes the influence of the network geometry and fractures properties on the overall performance of the reservoir.

From the uncertainty analysis results, we find that the overall reservoir performance is controlled by the fracture connectivity and the distribution of conductivity within the network. A good match of production history can be achieved by adjusting the fracture connectivity. Modeling with multiple realizations of fracture networks acknowledge that a reliable production forecast is achievable using geostatistical analysis for fracture connection reconstructions. Applying Embedded Discrete Fracture Model (EDFM) on the fracture-related model simulation provides a robust and effective means of investigating multiple fracture realizations.
Utilizing an Innovative Approach to Create Type Well Areas for Unconventional Gas Shales
Authors: Kreman Drew , Osholake Tunde
Published: October 2018

Three principal factors that influence shale gas productivity are the reservoir quality (geology), the fluid type (which affects drive mechanism), and the completion methodology (which is affected by geomechanics). Out of all the reservoir fluids, dry gas has the highest recovery factor. Within dry gas shale resources, fluid type is not as big a factor compared to other hydrocarbon types. With fluid type out of the equation, where does geology and geomechanics contribute in the assessment of type well (TW) areas? In most occurrences, the geology and geomechanics is unaccounted for and only the factors that influence or quantify productivity (EUR, Cumulative Production, etc.) are utilized to generate TW areas. This paper demonstrates a unique, innovative approach, combining well-known statistical learning methods with detailed geologic and geomechanical maps to derive "like" geologic areas, lending to common well productivity. This new approach, not only reinforces the necessity of geologic mapping work, but more importantly takes out the geologic bias, while statistically exploring the data for geologic similarities.

The approach outlined in this paper takes a slightly different approach from a previous study [1], which grouped wells into different type wells by productivity measures (e.g. flowing pressures, shut in pressures, condensate gas ratio, flow potential, and separator oil and gas gravity). This approach focuses on generating similar geologic areas built around grid-based geologic and geomechanical maps, and relating these common areas back to type well performance. The common approach taken by both studies is the application of statistical learning methods, specifically principal component analysis and hierarchical clustering, to explore and group observations into similar regions.

This study includes various datasets, which range from production data to detailed geologic data for a frontier gas shale play in North America, but is applicable to most unconventional gas shales. This approach utilizes unsupervised statistical learning methods and infers that we are not trying to be predictive, but rather explore what geologically is influencing the type well areas.

The results of this study show that unsupervised learning techniques applied in a meaningful way can be used to delineate type well areas. Actual production data (Gas Rate and EUR) was utilized to verify the type well areas that have been generated using this method. In conclusion, six type well areas were generated and ranked by production results. It is recommended by the authors to utilize this approach in any frontier shale gas basin, in order to better streamline a type well workflow.
Is Complexity of Hydraulic Fractures Tunable? A Question from Design Perspective
Authors: Yu Hao , Dahi Taleghani Arash , Gonzalez Chavez Miguel , Lian Zhanghua
Published: October 2018

Microseismic data and post-fracturing production have confirmed the positive role of fracture complexity on production enhancement in fractured wells. While operators are looking for different fluids and pumping schedules to enhance fracture complexity, the mechanisms ruling the process is not fully understood. This paper provides a comprehensive workflow to model the fracture pattern development by accounting for interactions with numerous natural fractures. We present a robust finite element model with adaptive insertion of three-dimensional cohesive elements for fracture propagation through the intact rock as well as the network of intersecting natural fractures. Cohesive elements are coupled with general Darcy's flow to incorporate fluid flow as well as elastic and plastic deformations of rock during initiation, propagation and closure of hydraulic fractures. Hydraulic fracturing treatment has been simulated for different natural fracture patterns. Fluid injection pressure fluctuations are observed while reopening natural fractures. The impact of operation schedules on network complexity such as hesitation time is investigated. The complexity of fracture network is characterized by the ratio of total fracture length to its effective radius from the wellbore. Our analysis has shown that in addition to the differential stress and the fracture intersection angle which are already determined by the nature, pumping injection rate and hesitation time can play a significant role in fracture branching and its diversion to different natural fracture sets. Higher injection rate is found to have a positive effect to overcome the resistance of natural fractures in different directions, and hesitation in the middle of pumping can force the fracture to divert into other directions, both of which help develop a more complex fracture pattern.
A New Algorithm for Processing Distributed Temperature Sensing DTS
Authors: Carr Timothy , Ghahfarokhi Payam Kavousi , Carney BJ , Hewit Jay , Vagnetti Robert
Published: October 2018

Distributed temperature sensing (DTS) was used to record temperature from early 2016 to present for a Marcellus Shale horizontal dry gas well, MIP-3H, located in Monongalia County, West Virginia. In addition, after wellbore clean-out with water and nitrogen a flow scanner production log was conveyed on March 02, 2017. The flow scanner provides one day of gas and water production from each of the 28 stages in MIP-3H and from each of the clusters. The DTS data provides an opportunity to inspect the reservoir for Joule-Thompson (JT) effect, a phenomenon that describes cooling of an non-ideal gas as it expands from high pressure to low pressure, and obtain a relative production attribute along the lateral of the MIP-3H. The original fiber-optic DTS data shows the temperature along the lateral; however, due to the geometry of the well with toe up and the presence of a small fault and minor water production at Stage 10 relative gas production of each stage cannot be directly determined from the raw DTS data. We present two methods to generate DTS attributes that can be used to better reveal relative gas and water production through time from each perforation cluster and each stage of the MIP-3H. The first attribute deals with the deviations of the DTS measurements from the calculated geothermal temperature, while the second attribute calculated the difference between DTS temperature and the average daily DTS temperature along the lateral of the MIP-3H. We show that the latter DTS attribute provides a more robust image of temperature variations regime along the lateral than the former attribute. Negative values of the DTS attributes reveals JT cooling, resulting from stages of the MIP-3H with higher natural gas production. A correlation analysis of the production log with the calculated DTS attributes suggests that the production log is not representative of the entire production life of MIP-3H well. Temporal correlation with the DTS attributes is highest close to the production log recording day (March 2, 2017) decrease rapidly and the weak correlation switches from positive to negative.
LPG Fracturing in the Marcellus Shale Using Public Domain Information
Authors: Myers Roger
Published: October 2018

In the late summer of 2009 an American oil and gas producer teamed up with a Canadian pumping service company and performed a series of Liquified Petroleum Gas (LPG) fracturing treatments in Pennsylvania's Marcellus Shale. A total of four stages were pumped on three different vertical wells in three different counties Centre, Lycoming, and Indiana.

Questions surrounding damage associated with pumping large volumes of fresh water in nano-to-micro Darcy shale along with environmental pressures about water supply and disposal led to consideration of an alternative, non-aqueous fracturing fluid.

A hydraulic fracturing process utilizing 100% LPG as a fracturing fluid to carry proppant into shale or a coal seam or other water sensitive pay zone was developed. The new LPG fluid could be easily viscosified with oil gelling chemicals allowing for excellent proppant transport.

LPG was an appealing choice of fracturing fluid because its phase behavior in the Marcellus Shale at bottomhole conditions would theoretically render it non-damaging. The fracturing process brought sand into the gelled LPG so that it could be pumped under high pressure and into created fracture geometry in a pay zone. With respect to well cleanup post-frac LPG held the promise of greater cleanup and improved effective fracture half-lengths.

This paper will provide details about the LPG fracs and the resulting production response using a mix of readily available public domain information and information obtained by service providers or vendors. Initially, it was author's intention to use only public data but changes in the local market made access to more information available. A comparison of LPG fracturing treatments with slickwater treated wells will be shown for two of the three wells. Concluding remarks will discuss the current state of LPG fracturing in North America and a possible explanation for production results that did not meet expectations.
Estimation of Fracability of the Marcellus Shale: A Case Study from the MIP3H in Monongalia County, West Virginia, USA
Authors: Zhu Yixuan , Carr Timothy R.
Published: October 2018

Hydraulic fracturing is critical to economic production of shale oil and gas from unconventional reservoirs. Success of completion is closely related to gas production. The brittleness index is widely used as a measurement of ability of hydraulic fracturing. However, the index may not be a unique and explicit indicator for estimating "fracability". In the Marcellus Shale of our study area, there is discrepancy between brittleness index calculated from mineralogy and that from elastic moduli. In addition, the brittleness index does not explain why the large majority of microseismic events were generated well above the Marcellus Shale. Two other factors appear to control fracture stimulation. One is the presence of pre-existing natural fractures. Natural fractures, measured and interpreted from the FMI log, show that fractures developed in similar patterns with high dip angle in the Marcellus and overlying Mahantango shale units, which are favorable for vertical fracture propagation. The other factor is geomechanical characterization. The Marcellus Shale has obvious presence of overpressure. According to the study on stress state using a Mohr's circle, overpressure in the Marcellus Shale increases the possibility of frictional sliding of pre-existing fractures especially at lower value of least principal stress, and will keep some fractures at certain dip angles open, although some of them are in non-active state. Unconfined compressive strength (UCS) is used to estimate rock strength in overpressure strata. The result calculated from empirical equations shows that the Marcellus Shale has significantly lower rock strength, which continues up into the Mahantango Formation, and explain vertical hydraulic fracture growth.
Application of Machine Learning Algorithms for Optimizing Future Production in Marcellus Shale, Case Study of Southwestern Pennsylvania
Authors: Shahkarami Alireza , Ayers Kimberly , Wang Guochang , Ayers Alivia
Published: October 2018

The Marcellus Shale has more than a decade of development history. However, there are many questions that still remain unanswered. What is the best inter-well spacing? What are the optimum stage length, proppant loading, and cluster spacing? What are the ideal combinations of these completion parameters? And how can we maximize the rate return on our investment? This study proposes innovative tools that allow researchers to answer these questions. We build these set of tools by utilizing the pattern recognition abilities of machine learning algorithms and public data from the Southwestern Pennsylvania region of the Marcellus Shale.

By means of artificial intelligence and data mining techniques, we studied a database that includes public data from more than 2,000 wells producing from the aforementioned study area. The database contained completion, drilling, and production history information from various operators active in Allegheny, Greene, Fayette, Washington, and Westmoreland counties located in the Southwestern Pennsylvania. Extensive preprocessing and data cleansing steps were involved to prepare the database. Various machine learning techniques (Linear Regression (LR), Support Vector Machines (SVMs), Artificial Neural Networks (ANNs), and Gaussian Processes (GP)) were applied to understand the non-linear patterns in the data. The objective was to develop predictive models that were trained and validated based on the current database. The predictive models were validated using information originating from numerous wells in the area. Once validated, the model could be used in reservoir management decision-making workflows to answer questions such as what are the best drilling scenarios, the optimum hydraulic fracturing design, the initial production rate, and the estimated ultimate recovery (EUR). The workflow is purely based on field data and free of any cognitive human bias. As soon as more data is available, the model could be updated. The core data in this workflow is sourced from public domains, and therefore, intensive preprocessing efforts were necessary.
Production Facility Emissions Reduction in Liquids-Rich Shales: An Update
Authors: Porter Matthew , Natili Rich , Strathman Andrew
Published: October 2018

Operators in unconventional shales are constantly looking for ways to reduce potential emissions from production facilities. This is especially challenging in liquids-rich regions, such as the Marcellus Shale, which is highlighted. As regulations and various industry best practices evolve, facility designs and equipment must evolve as well. Examined are facilities design improvements and successful operational procedures to eliminate or significantly reduce emissions.1

By taking a proactive approach, operators can reduce emissions significantly. In review, an earlier paper (M.D. Porter et. al., 2016) discussed the key elements to a successful program: (1) a facilities design and operational philosophy that takes emission controls into consideration, (2) a comprehensive maintenance program that addresses all unplanned or unintended releases encountered during optical gas imaging inspections and allows for feedback to facilitate corrective action, and (3) a focused plan for improving technology to diminish the quantity of future leaks. Applying enhanced technology, and lessons learned, to older designs is often the most efficient measure for reducing potential emissions. While these elements are crucial, equally important is the historical defining and tracking of actual identified leaks and documentation of corrective actions that have been taken.1 This paper further corroborates these key elements.

Additional facility designs for maximum emissions reduction will be compared to facility designs in the previous work using calculated emissions for each scenario. As well production increases from drilling longer laterals and enhanced stimulation practices, well site liquids handling and vapor control can become challenging. Techniques for effectively controlling vapors and mitigating emissions are explored in detail using an actual case study. Also, a previous leak detection field study with preliminary data is updated with additional years of data, which yields further clarification of emissions released on a field and pad level and resulting variations with time. Using detailed data analysis resulting from inspections, the most common areas where leaks occur within a production facility area are identified - the majority of which are located on atmospheric stock tanks. Data further demonstrates the effectiveness of higher quality tank relief valves for reducing fugitive leaks.

Production facility emissions can be managed utilizing effective production facility designs and technologies. The present work offers an improved understanding of how technological evolutions can support effective design solutions and processes in a modern shale gas development.1