bluuebunny/crossref_metadata_2025 huggingface dataset:
Progression Through Technology: Results of Acid Systems Application to Improve Injectivity of Horizontal Wells in Caspian Offshore Oilfield
Authors: Golenkin Mikhail , Khaliullov Ildar , Vereschagin Sergey , Ovsyannikov Dmitry , Kobets Vladimir , Kulinich Nikolay
Published: October 2018

Yuri Korchagin field, located in the Russian sector of the Caspian Sea, is one of the largest field on the Caspian shelf with proven reserves stand at 29 million tons of oil and 63 billion cubic meters of gas. Since the beginning of commercial operation, in the spring 2010, the field production passed eight million tons of oil. The operator company conducts development of Yu. Korchagin field by a system of horizontal wells with a length up to 8000 m, from a fixed offshore ice-resistant platform, installed in the dome area of the structure. The main challenges in the field development are associated with premature water and gas breakthroughs at high permeability intervals of horizontal wells. Currently, as a result of the sharp increase in the field water cut, the oil production is constrained due to the existing limitations on volume of produced water that can be utilized in the conditions of the offshore field. Two water-injection wells were drilled and commissioned to utilize produced formation water into the aquiferous zone of the carbonate reservoir. In order to restore and increase the injectivity factor, small-volume acid treatments are carried out yearly on the carbonate reservoirs in the lower horizontal sections of the water-injection wells. Since 2014, more than 20 matrix and hydrochloric acid treatments were performed with application of acid systems of different compositions and volumes. In some cases, the wells injectivity increase after matrix acidizing treatments with traditional acid systems was below expectation, demonstrating limited and short-term effect. Therefore, with constantly increasing volume of produced water at the field, it was required to increase the frequency of acid treatments to maintain the appropriate level of injectivity of the water-injection wells. The additional treatments are associated with significant time and financial costs because of the offshore platform standby and production suspension. The need exists to improve efficiency of acid stimulation treatments performed in the field to achieve sustainable increase in injectivity index of existing wells.

The purpose of this study is to analyze acid stimulation treatments carried out on carbonate reservoirs of the horizontal water-injection wells in 2014-2017, evaluate the efficiency of the treatments with different acid systems to change the injectivity factor, discuss the prospects for their application in Yu. Korchagin field and formulate recommendations for further efficiency improvements of acid stimulation treatments in the field.
Dynamic Fluid Diversion with Advanced Pressure Monitoring Technique – New Era of Multistage Refracturing in Conventional Reservoirs of Western Siberia
Authors: Borisenko Alexey , Parkhonyuk Sergey , Danilevich Elena , Loginov Arkadii , Butula Kreso , Fedorov Andrey , Tetyuk Dmitry , Kapkaev Aleksandr , Makhmutov Ruslan , Tsygulev Ivan , Ibragimov Kenes , Letko Ivan , Mingazov Artur , Volkov Alexey , Ivanov Alexey , Samoilov Ivan
Published: October 2018

Drilling of the horizontal wells in Russia is increasing both regarding the numbers of wells and meterage. Recently, one of the NOC reported 47% increase in a number of horizontal wells. It is clear now that shift towards horizontal wells completed with multi-stage hydraulic fracturing is increasing.

On the other hand, an economic lifetime of these wells not always met.

For the vertical well, a well-known and successful technique for the well revitalization is re-fracturing. Vertical wells have been responding so positively, that some operators perform refracturing up to four times on the same well.

In case of the horizontal well, one of the most significant uncertainties is the fluid entry point. Starting from uneven depletion of the horizontal part of the well, not knowing the fluid entry point may lead to ineffective well re-stimulation and absence of any positive effect.

In this paper, we will demonstrate integrated approach towards horizontal well re-stimulation: starting from proper reservoir evaluation and candidate selection to engineered treatment design. Several novel methods and techniques have been used: dynamic diverting agent, that has been developed to fit particularities of the conventional reservoirs, and high-frequency pressure monitoring technique, which has served as an engineering tool for fluid entry point validation.
Propped Fracturing in Deep Naturally-Fractured Tight Carbonate Reservoirs
Authors: Che Mingguang , Wang Yonghui , Peng Jianxin , Meng Leifeng , Zhu Raoyun , Huang Longcang , Wang Liao
Published: October 2018

Over the last ten years, thirty wells were performed by proppant fracturing in deep naturally fractured tight carbonate reservoir in Tarim oilfield, including twenty-two hydraulic fracturing wells and eight acid-carrying-proppant fracturing wells. This paper will introduce what we have done for the proppant fracturing, what affect the fracturing and post-production, and why acid-carrying-proppant fracturing was tested and its result.

Natural fractures and vugs are the main hydrocarbon reservoirs in Tarim oilfield, and acid fracturing was used to increase the production. But post acid-fracturing production was low in the tight carbonate with fissures, so proppant fracturing was referred to the poor formation with the purpose of increasing prop- length, enlarging discharge area and maintaining post rate in vertical wells.

In order to realize the successful hydraulic fracturing in deep openhole wells, some measurements were taken to ensure the treatments such as large scale pad-fluid, 2-6 stages slugs, high pumping rate under the safe treating pressure, small-sized high-strength ceramic proppants and long step concentration with low-medium proppant. There were eight wells sand screenout or sand screenout behavior during treatment in the twenty-two hydraulic fracturing wells, which is mainly attributed to the presence of natural fractures. The hydraulic fracturing's difficulty was depended on natural fractures, there were seven fracturing wells with annulus pressure no packer, four wells' casing pressure increased 10 MPa-25 MPa because of the natural fractures and three wells' casing pressure increased only 4 MPa-6 MPa for no or poor natural fractures while fracturing. Micro seismic results showed that multi-fractures propagated while fracturing, the extending direction of secondary fractures had a large angle with the principal fracture, which ultimately leads to complex propped fractures. The post-fracturing temperature logging shows that the fracture height is about 30 m. The post-fracturing evaluation demonstrates that the half-length of the artificial fracture is 100 m-150 m. Meanwhile, seven acid-carrying-proppant fracturing with the purpose of acid etching fracture and propping fracture were treated in the fissure-matrix carbonate, and the results were not all good for the deep vertical carbonate wells.

Natural fractures and holes are important for post-rate of proppant fracturing, some well even has been producing for 10 years, for reservoirs with rare natural fractures and dissolved pores and caves, the post-fracturing production is low or declines rapidly.
Breakdown Pressure Considering Infiltration and Pre-Existing Fracture in Tight Sandstone Formation
Authors: Guo Jianchun , Li Mei , Deng Yan , Yang Ruoyu , Liu Yuxuan , Zhou Chao
Published: October 2018

Fracturing stimulation in deep tight gas reservoir in Eastern Sichuan Basin China shows that natural fractures obviously affect the treatment pressure. Accurate determination of breakdown pressure in the presence of pre-existing fracture can assist engineers better manage expected fracture gradients. The available fracture models for breakdown pressure prediction did not consider possible failure mode of hydraulic fracture influenced by pre-existing fracture. In addition, Elsworth indicates that breakdown pressure is a strong function of fracturing fluid infiltration. Infiltration due to pre-existing fractures is non-negligible to breakdown pressure prediction.

To overcome the limitation of current models, a model considering pre-existing fracture is applied to predict breakdown pressure. The stress distribution of pre-existing fracture intersected with perforation hole considering fluid infiltration is described based on stress distribution model of ellipsoid. The breakdown pressure prediction model is built considering uniform stress distribution and 3 possible failure mode, which are tensile failure of matrix, tensile failure of pre-existing fracture and shear failure of pre-existing fracture, described by corresponding failure criterion.

Sensitivity studies are conducted to investigate the influence of pre-existing fracture dip angle, orientation and location on failure mode and breakdown pressure. It indicates that the distribution of pre-existing fracture has great effect on hydraulic fracture failure mode and corresponding breakdown pressure. The breakdown pressure (1) increases with increasing dip angle and decreases with increasing orientation when matrix fails, and (2) doesn't always show the same tendency when pre-existing fracture fails. The novel model is further verified against measured breakdown pressure from field fracturing treatment of M3 well in deep sandstone formation in eastern Sichuan Basin.
Expanding Boundaries of Multistage Hydraulic Fracturing with Coiled Tubing in Novoportovskoe Field
Authors: Belov Alexander , Tishkevich Sergey , Simakov Sergey , Kichigin Anatoly , Burdin Konstantin , Maskhadov Movsar , Ishangaliev Askhat
Published: October 2018

Today, when most reservoirs have low productivity, the question of whether hydraulic fracturing can be applied to the oil rims becomes very important. It was revealed that the efficient way to compensate the fractures and formation contact area under conditions of a necessary hydraulic fracturing reduction was the implementation of a special well completion technology, during which renewable frac sleeves were installed in the fullbore diameter of a liner, with sleeve density being increased for a reliable coverage of the well horizontal spacing with longitudinal fractures (Ishangaliev et al., 2017).

In the complex geological conditions of the Novoportovskoye field, a fundamentally new solution was proposed for horizontal well completion – full bore MSF system with sliding sleeves, operated by hydraulic shifting key with coiled tubing (CT). This completion system allows to perform MSF without pulling CT out of the well to the surface and instantly use CT for well clenout in the case of screenout (SO). This decision is aimed to increas production and achive economic efficiency of the field development by increasing the formation coverage by means of larger number of MSF stages per well, and optimizing costs by reducing the time for the entire range of work at the well, that was detailed described by Kazakov et al., 2017.

An outstanding example of oil rim stimulation and application of new technology was a project in Novoportovskoye field where 30- and 27- stage mulstistage fracturing operations were successfully performed with shifting ports comopletion operated by coiled tubing.
Features of the Well Testing and Plt Works During Well Construction From SSDR in Okhotsk Sea
Authors: Magerova Anna , Semenov Yury , Ershov Nikolay
Published: October 2018

Inorder to confirm calculated values of operating production rates for new wells, flow coefficients A and B, draw-down pressure it is crucial to ensure the variation range of production rate reaching the design value at the stage of well development and initial gas dynamic testing at steady flow modes.

Increased volume and improved quality of received data at the stage of well drilling and development allows to enhance reliability of design solutions and avoid time and financial expenditures for additional survey.

Upon construction of exploration and high-rate production wells in offshore fields it is not possible to conduct full-scale initial gas dynamic testing in course of well development. Therefore, the required accuracy of forecast calculation of well operation mode and, subsequently, customization of the hydrodynamic model, cannot be assured to the full extent. Gas dynamic well testing offshore is limited due to specific nature of work performance and specifications of development units of semisubmersible drilling rigs.

The limits are primarily associated with the throughput capacity of the utilized separation equipment of semisubmersible drilling rig (maximum allowable rate), well design and the time allowed for well development.

Kirinskoye gas condensate field is located in the shelf of the Sea of Okhotsk along the north-east coast of the Sakhalin is land within Sakhalin-3 project Kirinskiy prospective site. The field is the first hydrocarbon development site of Gazprom in the shelf of the Russian Federation where subsea development system was utilized, which demands higher standards for development project design performance control.

The construction of production wells was being conducted with the utilization of semisubmersible rigs Polyarnaya Zvezda (Polar Star) and Severnoye Siyaniye (Northern Lights). In 2017 two gas condensate production wells were completely constructed and temporarily shut down until connection to the subsea gathering and transportation system for produced formation fluid.

During exploration drilling of the wells in Kirinskoye gas condensate field gas dynamic testing was carried out selectively and cannot be used to the full extent for forecasting and correlation with the results of gas dynamic testing of production wells.
Short-Time Periodical Well Operation in LLC LUKOIL-West Siberia Fields. Implementation Experience and Prospects for Development
Authors: Abdullin Artur , Abdulin Ilnur , Sokolyanskaya Yekaterina
Published: October 2018

Basic constituents of oil production costs include production specific volumes, electric power consumption, equipment costs and costs for production operations and well survey. Methods to increase oil production profitability currently used are usually aimed at improving only one of the above mentioned factors and often to the detriment of another factor. Short-time periodical operation of oil production wells using an ESP unit allows improving all the basic constituents of oil production profitability.

In the work presented we chose to analyze the fields of LLC LUKOIL-West Siberia.

The scope of the work is to examine the implementation experience of this technology, reveal its advantages and disadvantages and perform a technical and economic assessment of the advisability of the technology further implementation in LLC LUKOIL-West Siberia fields including a wide-scale implementation.

The performed assessment and work results will be further used to reduce costs for downhole pumping equipment operation and maintenance.
To Modeling of Dual-Porosity Reservoirs
Authors: Lugumanov Timur
Published: October 2018

Simulation of naturally fractured reservoirs is a challenging task. First of all, due to complexity of the geological structure and the structure of the pore space. Anisotropy of fluid flows and difficulty in assessing the recoverable reserves are results of the complex structure.

Naturally fractured reservoirs can be classified into five types according to capacitive and conductive properties of fracture network and porous matrix blocks. Reservoirs, in which capacitive and conductive properties predominate in the fractured medium.Reservoirs, in which the capacitive properties predominate in the matrix medium, and the conductive properties predominate in the fractured medium.Reservoirs, in which the capacitive properties predominate in the matrix medium, and the conductive properties are strong enough in both the fractured and matrix medium.Reservoirs, in which the capacitive properties predominate in the matrix medium, but at the same time the pore volume of the fractured medium also has a significant influence on the reserves, usually due to the cavernous nature of the fractured medium. The conducting properties in such reservoirs are strong enough in both the fractured and matrix medium.Reservoirs, in which only the matrix medium has the capacitive and conductive properties, and fractures act as barriers.

The first two types of reservoirs are modeled by dual-porosity model. The third and fourth types are modeled by dual-permeability model. And the fifth type can be represented by the single-porosity model with features, description of which is beyond the scope of this article.

In this paper, on the basis of literature review and personal experience description of dual-porosity/ dual-permeability models are given. The filtration equations of dual-porosity / dual-permeability model and the description of the mechanisms of flow between the pore medium and the fractured medium are presented.

The sensitivity analysis was carried out. It demonstrated that the effective permeability of the fractured medium depends on the absolute permeability of the pore medium in numerical simulation.
Methanol Delivery Recycle Systems Development at Complex Gas Treatment Unit of Achimov Deposits of Urengoyskoe Oil and Gas-Condensate Field
Authors: Koryakin Alexander , Ermolaev Aleksander , Kagarmanov Aidar
Published: October 2018

When developing hydrocarbon deposits, an important task is the development and implementation of energy- and resource-saving technologies. Prospects for the development of Gazprom dobycha Urengoy are associated with the commissioning of deposits of the Achimov stratum. For the preparation of gas from these deposits, the design solutions include the use of low-temperature separation units with a recirculation scheme for the use of methanol.

The article describes the development and implementation of technical solutions on improvement of recirculation schemes of the use of methanol in the Achimov gas fields. The design solutions on optimization of methanol consumption at the gas treatment plant of the area 2A of the Urengoy field were not fully realized because of the hydrate deposition when feeding liquid from the intermediate separation stage to the low-temperature stage. The analysis of methanol distribution between the outgoing streams of the complex gas treatment plant showed that the main methanol losses occur with unstable condensate.

Specialists of Gazprom dobycha Urengoy LLC developed two technical solutions aimed at reducing methanol consumption. The first solution involves feeding the liquid phase from the intermediate separation stage to the low-temperature stage by means of an ejector. The second solution is based on the aqueous extraction of the reagent from the condensate with a mixture of formation water and the aqueous phase after methanol utilization in the stripping column. The implementation of these technical solutions makes it possible to reduce methanol consumption in gas treatment plants by about twice. A list of activities on improving the recirculation technology of the use of methanol in Achimov gas treatment plants has been determined. The first technical solution has already been implemented in the gas treatment plant of the area 2A and has proved its effectiveness
Digital Integrated Modeling for Waterflooding Management
Authors: Povyshev Konstantin , Valiev Rinat , Rechkin Mikhail
Published: October 2018

Gazprom Neft has set an ambitious strategic goal: reach up a production plateau at 100 million TOE per year. To achieve this goal, the company will need to increase the resource base, develop and commission new fields, and work with the basic production at the existing assets.

As of today, 95% of the company's fields are produced with a reservoir pressure maintenance (RPM) system. The reservoir pressure maintenance system is the key to ensuring sustainable production of an oil field. Condition and operation of this system have immediate effect on the reservoir behavior, displacement parameters, and, therefore, oil production profile. However, almost all of Gazprom Neft's subsidiaries are facing the problem of analyzing and interpreting field performance data because the process is too long and complex while its results are not obvious and unambiguous. For this reason, it may not always be clear in what part of the system there is a problem: the reservoir, the well or the infrastructure.

Let us turn to the widely known formula used to determine the oil recovery factor (ORF) (1): (1)ORF =KsweepxKdispl.

where Ksweep is the sweep efficiency (factor), and

Kdispl. is the displacement efficiency (factor).

Ksweep is the ratio of the volume of the reservoir being drained by the wells to the total volume of the reservoir. The sweep efficiency characterizes the effect of reservoir discontinuity (alternation of permeable and impermeable bodies) on the filtration parameters, i.e. how the drained volume of the reservoir is reduced compared to the case when the reservoir does not contain any impermeable bodies in it.

The main task when developing the reservoir then is to ensure full involvement of its entire volume in the process of drainage. But with a high degree of heterogeneity or a significant difference in mobility of oil and the displacing agent, flooding efficiency decreases which is expressed in lower sweep efficiency too. The main reason for that is the uneven propagation of the injected water front over the area and cross-section of the reservoir.

Kdispl. is the ratio of the volume of oil displaced by water from a reservoir rock sample or reservoir model till 100% water cut to the initial volume of oil contained in the rock sample or reservoir model.
Redefining Bakken Completions – A Tailored Approach to Stimulation
Authors: Trainor Kyle , Vincent Mike , Finch Ron
Published: October 2018

The economic boundaries of the Williston Basin are being expanded with improved practices. This paper discusses advances in reservoir characterization coupled with the implementation of refined stimulation techniques that have achieved strongly compelling results in an area of the Williston Basin that was previously perceived to be marginally economic.

After more than a decade of intense development, the remaining undrilled acreage in the core of the Bakken has been drastically reduced. Consequently, there is strong motivation to identify additional economically viable drilling locations. Hydraulic fracturing treatments incorporating increased volumes of fluid and proppant in more closely spaced clusters have successfully increased well productivity in many resource plays across the industry. The contemporary slickwater and slickwater hybrid designs implemented in the Bakken have spurred a renaissance of continued development throughout the basin. While these increasingly large frac treatments improve well productivity, in some parts of the basin the high treatment expenses and resulting elevated watercuts challenge the economic viability of development.

Rote application of the "bigger is better" completion strategies developed for the core of the basin has been unsuccessful in some portions of the Bakken. This paper describes the unique geologic characteristics of the study area and the stimulation strategy that has been adapted to accommodate the geologic differences while achieving excellent economic results. Implementation of completion designs tailored to the area has yielded a 300 to 400% production increase compared to offset wells. This "right sized" completion strategy customized for the area achieved highly productive wells with substantially lower capital costs than were budgeted based on strategies currently popular in the core of the Bakken. Although treatment designs continue to evolve and additional improvements are anticipated, the summary of experimentation and learnings from seven sequential wells may be helpful to others pursuing assets considered "marginal".
A Fast-Paced Workflow for Well Spacing and Completions Design Optimization in Unconventional Reservoirs
Authors: Belyadi Hoss , Smith Malcolm
Published: October 2018

Well spacing optimization is one of the most important considerations in unconventional field development. The Appalachian basin development has been increasingly prevalent in the last decade due to substantial production performance from Marcellus, Upper Devonian, and Utica/Point Pleasant Shale plays. The majority of operators have been in a manufacturing mode, where a standard well spacing and completions design have been applied to a field with less emphasis on optimizing the net asset value of the field. NAV can be improved through modeling and various optimization workflows such as numerical simulation, machine learning, and linear programming. The essence of field development and optimization is to use completions design, as well as well spacing, to optimize the net present value of the field based on current commodity pricing, capital expenditure, operating cost, cycle time, and net revenue interest. A substantial change in any of these essential factors must be studied to make sure the appropriate changes are accounted for in the field development and optimization.

Determining the optimum well spacing that coincides with the completion design can often be challenging and time consuming due to complexity of some governing factors such as geology, engineering, and economic analysis. For instance, if optimum well spacing and completions design were developed in a geologically noisy and complex reservoir, the outcome may no longer be valid in a discreet and quiet area. In addition, if well spacing and completions design were developed for a high commodity pricing environment, performing the same workflow and evaluation at a lower commodity pricing would yield an increase in well spacing. The dynamic nature of the oil and gas industry, specifically these essential factors, could cause complications with selecting the optimum well spacing and completion design to maximize the shareholder's value. Therefore, a fast-paced and dynamic workflow has been developed, that can be applied in different shale reservoirs, to maximize the present value of these assets. This paper will walk through the step-by-step process that can be applied to any unconventional shale play to optimize the field considering geology, engineering, and economic analysis.

The objective of this paper is to go through a fast-paced optimization workflow, starting with a fracture model, coupled with a production model using numerical simulation to obtain a calibrated model, and finally performing detailed economic and sensitivity analysis to obtain the optimum well spacing and completions design, which would yield the highest net present value of the field.
Characterization of Fracture-Driven Interference and the Application of Machine Learning to Improve Operational Efficiency
Authors: Klenner Rob , Liu Guoxiang , Stephenson Hayley , Murrell Glen , Iyer Naresh , Virani Nurali , Charuvaka Anveshi
Published: October 2018

Frac hits are a form of fracture-driven interference (FDI) that occur when newly drilled wells communicate with existing wells during completion, and which may negatively or positively affect production. An analytics and machine-learning approach is presented to characterize and aid understanding of the root causes of frac hits. The approach was applied to a field data set and indicated that frac hits can be quantitatively attributed to operational or subsurface parameters such as spacing or depletion. The novel approach analyzed a 10-well pad comprising two ‘parent’ producers and eight ‘child’ infills. The analysis included the following data types: microseismic, completion, surface and bottomhole pressure, tracers, production, and petrophysical logs. The method followed a three-step process: 1) use analytics to assess interference during the hydraulic fracturing and during production, 2) catalogue or extract feature engineering attributes for each stage (offset distance, petrophysics, completion, and depletion) and 3) apply machine-learning techniques to identify which attributes (operations or subsurface) are significant in the causation and/or enhancement of inter-well communication. Information fusion with multi-modal data was also used to determine the probability of well-to-well communication. The data fusion technique integrated multiple sensor data to obtain a lower detection error probability and a higher reliability by using data from multiple sources. The results showed that the infill wells completed in closest proximity to the depleted parents exhibit strong communication. The machine-learning classification creates rules that enable better understanding of control variables to improve operational efficiency. Furthermore, the methodology lends a framework that enables the development of visualization, continuous learning, and real-time application to mitigate communication during completions.
Thru-Tubing Workover Motor Load Measurements and Analysis
Authors: Landry Miles , McEntire Caleb Mac
Published: October 2018

By some industry estimates over 80% of hydraulically fractured land wells in North America employ the plug-and-perf method for zonal isolation. The dominant method for composite frack plug removal is through the deployment of a tubing conveyed hydraulically powered motor, or workover motor (WOM), to mechanically drill through plugs and remove the debris from the wellbore. Over 90% of Thru-Tubing Intervention (TTI) service companies provide to its customers is the application of WOMs to remove composite frack plugs. The effects of a mechanical failure in one of these motors during drillout operations is costly to both the customer and the respective service company. In many cases, a mechanical failure can cost several days of non-productive time (NPT) and more than double the financial burden of a drillout operation for both parties. A need was identified to validate traditional industry assumptions and refine drillout procedures by measuring and analyzing loads experienced by WOMs during live operations.

The purpose of this project is to measure and analyze the actual forces experienced by a WOM downhole during a live coil tubing conveyed drillout operation in order to experimentally prove or disprove industry tribal knowledge regarding the effects of traditional drilling parameters and procedures on downhole equipment and operational efficiency. The project involves the use of a data logging sub capable of measuring these forces in the bottom-hole-assembly (BHA). By examining the collected data; patterns and trends will be identified which give insight the most efficient procedures and drilling parameters as well as validate whether equipment is being utilized within operational limits under traditional assumptions. Additionally, the collected data could be used to identify additional opportunities to further improve the design, manufacturing, maintenance and operation of WOMs to meet the evolving challenges of drillout operations involving increased lateral lengths and stage counts.

These improvements to plug drilling procedures will reduce risk, operational time, and cost at the well site as well as internal cost associated with repairing and investigating potential mechanical failures that arise from operating WOMs beyond their limits. Future operations that include the measurement of downhole forces will enable even greater advancements in product reliability across the TTI product portfolio to further reduce the risk of additional time and financial costs to service companies and their customers.
Analysis of Various High Viscosity Friction Reducers and Brine Ranges Effectiveness on Proppant Transport
Authors: Aften Carl
Published: October 2018

Friction reducers (FRs) are used to decrease the amount of horsepower required to move a hydraulic fracturing fluid through a formation at a fixed flow rate. Though FR viscosity is not a crucial consideration in proppant transport when used before the perforations in slick water applications, FR viscosity becomes a greater consideration in proppant transport from the perforations into the formation and an important qualifying criterion with the advent of High Viscosity Friction Reducer (HVFR) systems that require higher loadings than traditional FRs. Consistent viscosity measurement can vary greatly depending upon a number of factors, for example temperature, hydration approach, polymer concentration, brine composition, and additive interaction. A study was developed and implemented to determine the influence of HVFR by concentrated particulate and bead settling.

This study investigated the viscosities of five HVFRs applying eight variables using response surface methodology. Initial study criteria were establishing consistent hydration with unique apparatus design and viscosity measurement verification. Once established, this method examined the effects of 1:1, 2:1, and 2:2 salts, singularly or in various concentrations and combinations. Experimental designs under fresh water conditions were also conducted with varied HVFR loadings (1.0 to 6.0gpt), blender RPM (600 to 12,000), and blender mixing times (0.5 to 8.7 minutes). Viscosities were measured from 200 to 6000 (1/sec). Static settlement testing in ranges of 0.87 to 3.50 pounds per gallon in 0 to 140,000 total dissolved solids (TDS) brines was conducted. Single bead settling measurements were performed in fresh water and API brine.

Specific HVFR and salt matrix combinations tested resulted in highly correlated response surfaces exhibiting consistent trends. The TDS and hardness had a minor to major influence on viscosity based upon the specific HVFR examined. Brines were predominately antagonistic with respect to viscosity with few synergistic results. The influences of HVFR dosage and mixing correlated highly to the viscosity of all HVFRs, and extended mixing time durations had no influence on some HVFR combinations indicating a viscosity reduction limit. In certain regions of the design space, settling rates were related to viscosity.

Selection of an HVFR system precisely tailored for a specific brine composition guaranteeing maximum friction reduction and proppant transportation performance was vital. The influence of pumping and tubular transport on the HVFR viscosity is continuous and quantifiable. Additionally, the viscosity of the HVFR in a downhole brine environment provides discernable data for assessing far end well bore proppant transport and damage potential. This study established a reliable method for gauging performance and examining measurable field variables of HVFR systems.
A Fast EDFM Method for Production Simulation of Complex Fractures in Naturally Fractured Reservoirs
Authors: Xu Feng , Yu Wei , Li Xiangling , Miao Jijun , Zhao Guoliang , Sepehrnoori Kamy , Li Xianbin , Jin Jianli , Wen Guangyao
Published: October 2018

Natural fractures are the main producibility factor in the weathered granite reservoirs (basement rock) and volcanic-rock reservoirs. Production practices show that these reservoirs could have high production rate, but the difference of well productivity between single wells is obvious. These reservoirs have complex natural fractures oriented at medium-high angles, which could bring high complexity and heterogeneity to the reservoirs, adding anisotropy to reservoir permeability. It is very hard to effectively simulate complex fractures in naturally fractured reservoirs and study the applicability of different well type and well pattern by using common reservoir simulators. A fast EDFM (Embedded Discrete Fracture Model) method was put forward for production simulation of complex fractures in naturally fractured reservoirs. The EDFM processor combining commercial reservoir simulators (ECLIPSE or CMG) is fully integrated to forecast production performance of the weathered granite reservoir. With a new set of EDFM formulations, the non-neighboring connections (NNCs) in the EDFM are converted into regular connections in traditional reservoir simulators, and the NNCs factors are linked with gridblock permeabilities. So complex dynamic behaviors of natural fractures can be captured, which can maintain the accuracy of DFMs (discrete fracture models) and keep the efficiency offered by structured gridding. In this paper, a 3D model with complex natural fractures was built to model the performance of different well types and well patterns. The results show that wells with higher density of natural fractures produce higher oil production, and horizontal wells with higher density of natural fractures have larger oil production than vertical wells because horizontal wells have a larger contact area than vertical wells. What’s more, heterogeneity and anisotropy have a great effect on well pattern and well type, which need to be studied carefully in the oilfield development.
Reduced Cluster Spacing: From Concept to Implementation – A Case History
Authors: Deasy Michael , Brown Kenneth , He Jonathan , Lipscomb Wade , Ockree Matthew , Voller Katharine , Frantz Joe
Published: October 2018

This paper presents a case history and lookback on the Reduced Cluster Spacing (RCS) completion design that was initiated in 2012. We review results of the initial analyses used to demonstrate proof of concept, summarize key aspects of the completion design, and discuss execution and results of the initial pilot tests and subsequent field-wide implementation. We propose a method to incorporate results of RCS models into production forecasts, and quantify the impact of RCS designs on volumes and economics over time.

We begin by presenting proof of concept analyses used to justify the initial field pilot. We then discuss RCS field trials, commenting on key aspects of project design and operational execution. We compare RCS well performance to control wells using normalized production plots, discuss type curve (TC) forecasting for RCS wells, and touch briefly on more rigorous modeling of RCS completions. We present a methodology to incorporate results from rigorous models into simpler type curves suitable for quick economic analyses and volumetric comparisons. We conclude by reviewing the economic and production impact of RCS on production at the well level and field development level.

Case histories are presented demonstrating the use of a production normalization process to assess the value of different completion designs. We demonstrate that RCS completion designs have been successful in terms of both volumes uplift and economic performance. We describe positive and negative aspects of the route taken to implement this strategy in the field. We conclude that the use of "uplift factors" derived from modeling can be used to efficiently incorporate detailed model findings into typical engineering workflows for volumes and economics forecasting. As a result of the work presented in this paper, RCS completions have become the standard in our Marcellus wells.

This lookback will present a method to effectively demonstrate proof of concept for new completion designs and assess the field implementation of novel completion strategies. This method is demonstrated by quantifying the value of reduced cluster spacing achieved in the Marcellus. We also provide a simple way to incorporate complex model results into every day engineering and economic forecasts.
Flowback Fracture Closure of Multifractured Horizontal Wells in Shale Gas Reservoirs
Authors: Zhang Fengyuan , Emami-Meybodi Hamid
Published: October 2018

In multi-fractured horizontal wells (MFHW), fracture properties such as permeability and fracture half-length significantly deteriorate during early production, which negatively affects gas production from shale reservoirs. Therefore, it is crucial to evaluate the temporal changes in fracture properties based on production data. This paper presents a workflow in which both flowback and long-term production data are used to quantitatively evaluate hydraulic fracture closure and changes in the fracture properties. In addition, we develop a two-phase semi-analytical model based on rate transient analysis (RTA) that assumes boundary dominated flow during the flowback period. The proposed workflow consists of three steps. First, we used the flowback data to calculate fracture properties, such as initial fracture permeability and fracture half-length, by employing the two-phase semi-analytical model. Then, we calculated initial fracture permeability by using a single-phase bilinear flow model as well as the fracture half-length and matrix permeability by using a single-phase linear flow model from the long-term gas production data. These models consider pressure dependency of permeability. Last, we compared the results that are calculated from both flowback and long-term production data to evaluate fracture closure and its effects on fracture permeability. We validated the semi-analytical flowback model and the workflow against numerical simulations. The results show that the developed model is capable of predicting fracture properties and evaluating fracture closure. Furthermore, the proposed workflow provides quantitative insights on the performance of fracture stimulation and is able to closely estimate permeability modulus using flowback and long-term production data instead of conducting laboratory experiments.
Effect of Degradable Fiber Composition and Shape on Proppant Suspension
Authors: Collins Nick Allen , Grim R. Gary , Ghosh Koushik , Dorgan John R.
Published: October 2018

The ability of degradable fibers to reduce the settling rate of ceramic proppant in a guar-based solution was studied as a function of fiber composition and shape. Various cellulose ester fibers were benchmarked against a PLA standard.

Aqueous (2 wt% KCl in DI water) mixtures of degradable fiber, ceramic proppant, and guar were consistently mixed then allowed to settle. The position of the interface between the solids-rich bottom layer and solids-poor top layer was measured as a function of time for various fiber compositions, shapes, and loadings. Settling experiments were also repeated to determine measurement error. Viscosity measurements were performed both to determine appropriate guar loading and to investigate the effect of fibers on viscosity.

Consistent with recent results published in the patent literature for PLA, fiber shape was found to have a strong effect on proppant suspension. However, these effects went well beyond those found for aspect ratio and degree of crimping reported previously. Indeed, fiber cross-sectional shape was found to have a very strong effect with "X" and trilobal shapes showing better proppant suspension capability than round fibers. Fiber loading with shaped fibers could be reduced up to half of that round fibers with the same proppant suspension performance. The degradable polymer composition may play some role in proppant suspension but it appears to be secondary relative to that of fiber shape.

Degradable fibers with improved performance should enable broader consideration of their use for proppant transport, proppant suspension, and heterogeneous proppant placement in fiber-based hydraulic fracturing. Other stimulation applications may also value alternative degradable materials.
Quantification of Fracture Surface Roughness and Its Insights to Mechanical Rock Properties Determination Using Image Analysis Techniques
Authors: Gong Yiwen , El-Monier Ilham
Published: October 2018

During the hydraulic fracturing process, the rough surface of fractures and the viscous proppant suspension flow bring great challenges to the distribution of proppants evenly at the fracture thin apertures. As a result, a detailed understanding of the effect of surface roughness on proppant sedimentation seems essentially indispensable. Apart from that, how the roughness of Nano-scale conduits and their orientations, such as microfracture channels, affect the flow through the damaged fracture process zone (FPZ) have not been well understood.

A newfangled developed algorithm using image analysis software (ImageJ) is applied to characterize the morphological features of the damaged fracture system, including surface roughness, microcrack types and microcrack density indicators. Hydraulic fracturing experiment is conducted on a Tennessee sandstone core using a triaxial loading system. The fractured samples are ion milled, and its cross section plane images are recorded by scanning electron microscope (SEM). Statistical analysis of surface roughness, the degree of damage at FPZ, the density of microcracks and effective connection indicator of microfractures to the main fracture are quantitatively investigated, in addition to Young's modulus and Poisson's ratio.

We found that the higher roughness of microfracture network significantly enhances the effective conduits open to fluid flow while taking the density of the microfracture within FPZ into account within the fracture processed region, depending upon how much damage is presented. In other words, the overall ease of fluid delivery to the main fracture essentially depends on the level of the damage in FPZ. The heavily deformed rock grains cause a partial blockage at the fracture surface and will be detached on the main fracture. The leftover is the induced intercrystalline microfracture network in the vicinity of the main fracture. Additionally, mechanical moduli were interpreted by image analysis, where a novel approach was developed to calculate the mechanical rock properties. The results from image analysis were compared to other failure criteria and fracturing pressure data interpretation. We also validated the obtained mechanical properties by collating the literature records.

The microfracture network creates the significant incremental amount of fluid conduits to hydrocarbons. The better understanding of the fracture network serves as a valuable guide to the fracturing job design and managing the damaged FPZ. This novel approach will commit to supporting the lab measurements, gives field preliminary mechanical property assessment and lower the cost needed for hydraulic fracturing design.
Drawdown Management Optimization from Time-Lapse Numerical Simulation
Authors: Crespo Pablo Agustin , Cuervo Sergio
Published: October 2018

The Choke Management has been one of the "hot topics" in Unconventional Reservoirs since the negative impact in using an accelerated flowback has been demonstrated in many documented cases. Modern production practices have migrated from a Choke Management to a Drawdown Management Strategy to improve the control on the effective net stress over the proppant in order to prevent hydraulic fracture conductivity damage and maximize ultimate recovery. The strategy optimization is a complex problem that reservoir engineers are still trying to solve using different tools from empirical observations up to complex reservoir simulators that includes reservoir physics and the most advanced rock mechanics. This work contributes introducing an innovative workflow using a state of the art non-coupled numerical simulator, with the addition of time-steps one-way coupled calculations.

The methodology consists in using a commercial reservoir simulator to History Match Completion Treatment Pressures and then Production. Once this first step has been completed, a Pore Pressure Grid is extracted at different times and then used to calculate changes in the minimum stress according to the isotropic poroelastic equation. Finally, the effective net stress over the proppant is calculated. This process is repeated with different Drawdown Management Strategies until the optimization.

The complete workflow is introduced in a real case example where a robust dataset was available for a horizontal well. Finally, some assumptions and considerations are discussed and conclusions are extracted from this study.