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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 190323, “Gas Injection for EOR in Organic-Rich Shale: Part I—Operational Philosophy,” and paper URTeC 2903026, “Gas Injection for EOR in Organic-Rich Shale: Part II—Mechanisms of Recovery,” by Francisco D. Tovar, SPE, Maria A. Barrufet, SPE, and David S. Schechter, SPE, Texas A&M University. Paper SPE 190323 was prepared for the 2018 SPE Improved Oil Recovery Conference, Tulsa, 14–18 April; paper URTeC 2903026 was prepared for the 2018 Unconventional Resources Technology Conference, Houston, 23–25 July. The papers have not been peer reviewed.
This synopsis contains elements of two papers. In the first, the authors describe their comprehensive experimental evaluation of gas injection for enhanced oil recovery (EOR) in organic-rich shale. Experiments in preserved core demonstrated the potential of CO2 to extract the naturally occurring oil in organic-rich shale reservoirs, whereas tests in resaturated core plugs were used to compute accurate recovery factors, and evaluate the effect of soak time, operating pressure, and the relevance of slimtube minimum miscibility pressure (MMP) on recovery. In the second paper, the authors focus on the effect of fluid transport in organic-rich shale on recovery mechanisms under gas injection, and provide the rationale behind the proposed operational philosophy.
Part I—Operational Philosophy
Background. The notion that industry experience in the implementation of gas-injection methods in conventional reservoirs can be applied to unconventional reservoirs is a problematic one. A lack of understanding exists regarding the effect of contrast in mechanisms at the pore scale on the implementation of a gas-injection process. Experimental research so far, though encouraging, suffers from serious limitations. Also, there still is a significant lack of understanding of the mechanisms of recovery under gas injection for enhanced recovery in organic-rich shales.
In this paper, the authors base their investigation on experimental observations made in core plugs extracted from the reservoir interval, and show the development of a coreholder configuration that enables the physical simulation of the injection of gas through a hydraulic fracture in the laboratory. Then, this configuration is used to perform coreflooding experiments at the pressure and temperature conditions seen in the reservoir. Detailed descriptions and results of the experimental work are provided in the complete paper.
Summary. The authors begin by demonstrating that direct gas injection through an organic-rich shale matrix is not possible in a reasonable time frame. That discovery triggered the construction of specialized equipment and the development of a novel injection technique that resembles that of injection through hydraulic fractures. Using that technique,
nine experiments injecting CO2 in preserved organic-rich shale cores were performed. Only three of those experiments recovered a significant volume of oil, and the recovery factor was estimated to be between 18 and 62% of the initial crude-oil volume in the cores.
This demonstrated CO2 can be used to extract the naturally occurring oil in core plugs with extremely low permeability, where gas cannot be injected directly. Also, by coupling the coreflooding equipment developed in-house to a computed-tomography (CT)-scanner, this technology proved able to track the changes in density resulting from the mass exchange between CO2 and crude oil.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper URTeC 2890074, “Laboratory Investigation of EOR Techniques for Organic-Rich Shales in the Permian Basin,” by Shunhua Liu, SPE, Vinay Sahni, and Jiasen Tan, SPE, Occidental Oil and Gas, and Derek Beckett and Tuan Vo, CoreLab, prepared for presentation at the 2018 Unconventional Resources Technology Conference, Houston, 23–25 July. The paper has not been peer reviewed.
Commercial production from light oil, organic-rich shales in the Permian Basin has largely come from a solution-gas-drive recovery mechanism as a result of horizontal drilling and multistage hydraulic fracturing. These onshore, capital-intensive developments feature steep production declines and low expected ultimate recoveries. This paper involved laboratory experiments introducing miscible gases into core samples to investigate enhanced oil recovery (EOR) mechanisms for Permian Basin shales to provide information to design field tests for a huff ’n’ puff (HNP) recovery process.
The average recovery factor in the un-conventional resources is typically less than 10% with very steep decline rates, indicating enormous potential for EOR. In recent years, research efforts and field pilots of unconventional EOR have targeted the Bakken and Eagle Ford shales. Most focused on miscible-gas (either CO2 or produced gas) injection, while others investigated water-based chemical injection. This paper provides EOR fluid and core analyses in Permian Basin organic-rich shale, an unconventional hydrocarbon growth play with different geological, rock, and fluid properties from those of the Bakken and Eagle Ford plays. The experimental results from this paper were used to calibrate the operator’s unconventional EOR reservoir simulation and field pilot design.
Fluid properties such as equation-of-state (EOS) and minimum miscibility pressure (MMP) are extremely important because they are the fundamental designing parameters for any gas EOR project. In this study, oil and gas samples were collected in the well from perforations inside the Wolfcamp formation of the Permian organic-rich shale. A gas/oil ratio (GOR) of 1230 scf/bbl was chosen to recombine the separator oil and gas on the basis of observed solution GOR values before any increase caused by the flowing bottomhole pressure falling below the bubblepoint pressure.
The pressure/volume/ temperature (PVT) laboratory-testing program consisted of a constant-composition-expansion (CCE) test and a series of swelling tests with CO2. Using the recombined reservoir fluid (with a GOR of 1230 scf/bbl), a CCE test was performed at the reservoir temperature of 162°F to measure the bubblepoint pressure, single-phase oil density, and compressibility. The swelling test results were performed to tune an EOS to be used to calculate oil properties with increasing CO2 concentration during a CO2 flood.
An EOS model was generated to match the CCE data, viscosity data, and CO2 swelling-test data. To use this EOS for CO2 reservoir simulation, the reported system components were grouped, but the CO2 component was left ungrouped. Otherwise, it would be grouped with component C2. The minor component N2 was grouped with C1. All C4s and C5 were grouped together, as were the C6s. The C7+ components were divided into three pseudocomponents.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 191457, “Coupling Geomechanical Effects and Reservoir Dynamics for Modeling Rejuvenation in Unconventional Plays,” by R. Dutta, SPE, Drilling Info; R. Pinto, Sciences Po University; and J.C. Flores, S.M. Stolyarov, SPE, and J. Yang, Baker Hughes, a GE Company, prepared for the 2018 SPE International Hydraulic Fracturing Technology Conference and Exhibition, Muscat, Oman, 16–18 October. The paper has not been peer reviewed.
An integrated understanding of geomechanical effects, fracture propagation, and reservoir dynamics is critical in the efficient and cost-effective application of rejuvenation technologies for unconventional plays. While various reservoir models depicting the hydraulic-fracturing process are available in the industry, many tend to be simplified or do not capture the numerous parameters that affect both the initial and restimulation processes. This work takes a further step toward building a more-realistic picture of fracturing in unconventional plays.
A common assumption in reservoir simulation is that the proppant-fluid mixture is present in the hydraulic fracture before flowback and production. The quantity of water assumed to be present in the hydraulic fractures is a conjecture and is calibrated generally with production-logging tools. These assumptions may skew the results of hydrocarbon recovery.
A method of incorporating geomechanical aspects of fracturing into the model involves the concept of pressure-dependent permeability variation in natural fractures that results in formation of pressure-dependent stimulated reservoir volume (SRV). Hysteretic permeability models employed in numerical modeling can offer a description of the SRV and also can be used in addressing longer-term geomechanical effects in a practical manner. While this concept has matured in the context of modeling hydraulic fracturing in reservoir simulation, it is being newly applied in modeling refracturing treatments.
Because the importance of capillary effect in low-permeability formations is recognized, the authors also incorporate capillary pressure in their model. In addition to pressure-dependent permeability variation, results explain how capillarity is significant in understanding fluid migration, the trapping of fluid in the matrix, and, consequently, restimulation.
The main challenge in selecting good candidate wells for this study was in finding wells that targeted the same formation, used varying refracturing technologies, and had sufficient data to build a reservoir-simulation model with input for the reservoir properties.
After studying a large number of wells, the authors focused on two horizontal gas wells producing from the Barnett Shale. One well was identified to be refractured with a selective zone-treatment method, while the other used a method of fluid diversion. The wells are located approximately 3 miles from each other and approximately 1,600 ft from neighboring wells. These wells have differing production signatures, but this is not indicative of a difference in the performance of two technologies. Understanding the difference in performance may be key to planning a successful refracturing operation.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 190860, “Evaluating the Impact of Lateral Landing, Wellbore Trajectory, and Hydraulic Fractures To Determine Unconventional Reservoir Productivity,” by Piyush Pankaj, Priyavrat Shukla, SPE, Ge Yuan, and Xu Zhang, Schlumberger, prepared for the 2018 SPE Europec featured at the 80th EAGE Annual Conference and Exhibition, Copenhagen, Denmark, 11–14 June. The paper has not been peer reviewed.
Inconsistent production performance from wells completed in similar pay zones has been observed when shale formations are exploited through horizontal wells. This paper demonstrates the need to couple the wellbore model to the reservoir-simulation and hydraulic-fracturing model in shale formations to optimize well landing, trajectory profile, and long-term productivity. The authors aim to demonstrate and deconvolute the well-trajectory plan with an integrated parametric study that helps to improve well productivity.
To plan a well profile, two critical pieces of information are required: Lateral landing depth, and well trajectory originating from the landing depth. To reach the targeted landing depth, the well trajectory undergoes a certain buildup of curvature deviating from the vertical section and, eventually, when the landing depth is reached, the designed trajectory profile is maintained and continued for the horizontal wellbore. The authors evaluated well trajectory and well productivity on the basis of the effect of the following parameters to guide well-trajectory planning:
Geological Review of the Model
A 3D earth model in the Permian Basin for the Wolfcamp shale was used to develop a work flow for determining well landing and well trajectory. The Wolfcamp shale covers most of the Midland Basin and ranges in thickness from 200 ft in the north of the basin to 2,600 ft in the south. The entire play is dominated by a fine-grained, naturally fractured source rock. The depths range from 5,500 to 11,000 ft. The Wolfcamp is slightly overpressured, with the pressure gradient varying between 0.55 and 0.70 psi/ft. In the past few years, the Wolfcamp has become one of the most profitable and exploited unconventional plays in the US. Almost all of the operators are collecting a significant share of their well inventory, which yields over 1,000 BOPD routinely in initial-production rate. The production declines within a short period (6 to 9 months). The recovery factors remain in the single digits for most operators. The Wolfcamp, Spraberry, and Bone Spring formations are the most prolific in the basin.
Defining Landing Depth
The proposed solution considers applying an end-to-end cycle of a streamlined work flow that starts with sampling engineered landing location points in the geomodel defined by the user on the basis of reservoir-quality (RQ) cutoffs. The first step is building the geological model around the sweet spot. This geological model contains petrophysical and mechanical properties of the rock along the depth of the targeted interval.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 19311, “Data-Mining Approaches for Casing-Failure Prediction and Prevention,” by Christine Noshi, SPE, Samuel Noynaert, SPE, and Jerome Schubert, SPE, Texas A&M University, prepared for the 2019 International Petroleum Technology Conference, Beijing, 26–28 March. The paper has not been peer reviewed. Copyright 2019 International Petroleum Technology Conference. Reproduced by permission.
Recent casing failures in the Granite Wash play in the western Anadarko Basin have sparked deep concerns for operators in North Texas and Oklahoma. Hydrostatic tests made in the field show that current API standards do not assure adequate joint and bursting strength to meet deep-well requirements. This paper is part of an ongoing effort to minimize the likelihood of failure using data-mining and machine-learning algorithms.
Casing failure has long presented a challenge to the industry. The combined effects of design, dynamic borehole conditions, metallurgy, and handling have been challenging to quantify and predict accurately. Additionally, most casing-string challenges have been handled reactively instead of proactively; the total number of failures have been underreported and overlooked.
The authors focus on the effects of poor cement as a primary factor; this translates into the absence of cement in a case study presented in the complete paper. Additional factors are the pumping of corrosive acids and poor standardized casing design that does not account for varied formations along with cyclical temperatures.
Casing with partial cementation and sheaths with voids can contribute to excessive buckling-related collapse and tensile failures. Large pressure loadings, along with significant change in temperature, contribute to significant stresses in the intercasing annuli. In fragmentally cemented casing, tensile loading can show a great discrepancy between compression and high tension, with instances of failures in both the outer and inner strings. Additionally, cement thickening by downward flow could lack uniformity and could be prone to channeling. Air entrapment might occur, establishing bridges that hinder the process. Some authors in the literature related cementing failures with hole enlargements and washouts in long cement depths. The lack of cement support in those significant intervals exposed the casing to movement during drillpipe rotation, which triggered wear and ultimate buckling.
The data were descriptively visualized using methods such as box plots, mosaic plots, and trellis charts, while predictive techniques included artificial neural networks (ANNs) and boosted-ensemble trees. A statistical software package was used along with Python coding to implement the models and choose the most-significant factors contributing to failure. Data-preprocessing techniques were implemented. The process began with data cleaning to account for missing data, re-move the bias incurred by noise, and remove outliers. For missing values, multivariate normal imputation on the basis of all samples belonging to the same class was used. Then, several parameters from different databases were integrated. Data transformation involved standardizing the data by the subtraction of the mean value and the subsequent division by standard deviation from each feature. Categorical variables were converted to numerical values because models such as neural nets, regression, and nearest-neighbor involve only numeric inputs. The compiled data set comprised 78 wells. Caution should be taken when assessing its statistical significance.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 194269, “An Advanced Technique for Simultaneous In-Situ Inspection of Multiple Metallic Tubulars,” by Yanxiang Yu, William Redfield, SPE, Nicholas Boggs, Kuang Qin, Marvin Rourke, SPE, and Jeff Olson, SPE, GOWell International, and Mosunmola Ekije, Fluor Federal Petroleum Operations, prepared for the 2019 SPE/ICoTA Well Intervention Conference and Exhibition, The Woodlands, Texas, USA, 26–27 March. The paper has not been peer reviewed.
A new pulsed-eddy-current (PEC) electromagnetic (EM)-based tool called an enhanced pipe-thickness-detection tool (ePDT) has been introduced for the corrosion inspection of multiple pipes. The tool can measure the metal wall thickness of five concentric pipes with a maximum outer diameter (OD) of up to 26 in. This capability, along with the tool’s unique configuration, provides an advanced downhole solution for tubular evaluations of production, injector, and storage wells.
As hydrocarbon production and storage wells age and new production and storage wells are exposed to elevated concentrations of corrosive fluids, well-integrity monitoring is gaining more attention. These factors have influenced well-performance, safety, and environmental concerns. Early, periodic monitoring of tubular corrosion and other defects can reduce the risks of serious leaks or well failures in a cost-effective way.
Historically, the continuous sinusoidal-signal-based far-field eddy-current (FFEC) technologies have been developed and deployed for multiple-concentric-pipe average-thickness measurements. However, FFEC is adversely influenced by the strong interference of direct excitation signal transmission coupling and the EM skin effect; this reduces the pipe response because of a decreasing signal-to-noise ratio (SNR) that does not allow quantitative evaluation of more than two concentric pipes.
In contrast, the PEC-excited EM signal contains wideband frequency components from kilo-Hertz to sub-Hertz range. The low-frequency EM signals penetrate concentric metal pipes effectively. The induced PEC on each tubular has different initial amplitude and decay rates because of a combination of OD, thickness, and EM parameters. After excitation, magnetic-field changes triggered by a combination of mutual inductive interactions among the pipes, eddy-current diffusion, and damping are picked up by the receiving coil during the acquisition window. Research and field applications have proved that the PEC method is more reliable for average thickness detection in multiple pipes. In previous studies by the authors, three pipes with up to 17-in. OD can be detected by magnetic tools. However, because of the combination of high signal dynamic range, inadequate SNR, extraneous tool motion, and troublesome interference of pipe magnetization, it has proved difficult for these tools to quantify thicknesses of outer pipes reliably in the presence of more than three concentric tubulars or at ODs greater than 17 in.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 190852, “Open-Source Tool Kit for Micromodel Generation Using 3D Printing,” by Thomas D. Seers and Nayef Alyafei, SPE, Texas A&M University at Qatar, prepared for the 2018 SPE Europec featured at the 80th EAGE Conference and Exhibition, Copenhagen, Denmark, 11–14 June.
The paper has not been peer reviewed. In this paper, the authors present an open-source tool kit for the generation of microfabricated transparent models of porous media (micromodels) from image data sets using optically transparent 3D polymer additive manufacturing (3D printing or sintering). These micromodels serve as research and pedagogical tools that facilitate the direct visualization of drainage and imbibition within quasi-2D porous media, generated from a range of image modalities [e.g., thin section micrographs, µ-computed tomography (µCT) orthoslices, and conventional digital photography].
Though recent advances in 3D X-ray imaging, such as X-ray microtomography and µCT, permit volumetric imaging of microcore flood experiments with-in geological samples at the pore scale, experimental observations of dynamic (time-resolved) multiphase flow with-in pore networks still are obtained conventionally using transparent etched or molded synthetic porous media commonly referred to as micromodels. Typically, video footage of fluid imbibition and drainage experiments conducted across these quasi-2D pore networks is used to understand fluid distributions and displacement mechanisms within an equivalent 3D porous media. Contrary to state-of-the-art dynamic µCT coreflood experiments, which require synchrotron beam time to be conducted, micromodel studies can be undertaken routinely within a laboratory-based setting with a relatively simple experimental setup. However, the facilities required to fabricate micromodels typically are highly specialized, with production often outsourced to third-party manufacturers.
In this work, the authors consider the potential of using additive manufacturing (3D printing or sintering) as an alternative to conventional micromodel-fabrication techniques. With the advent of light-transmissible 3D-printable materials, flow experiments conducted with these 3D-printed physical models can be captured using widely available optical imaging techniques (i.e., standalone digital cameras and trinocular microscopes). However, a major obstacle encountered in harnessing 3D-printing technologies for the goal of micromodels fabrication is the paucity in software tools capable of processing and converting raster-based images to mesh-based file formats parsable by commercially available 3D-printing systems.
The paper aims to provide an open-source platform through which 3D-printable mesh-based representations of micromodels can be generated from raster imagery. Using this tool, standard micromodel components are fully integrated into the fabricated model. The availability of such a tool kit could act as an enabler for community research into fluid-transport phenomena in porous media. The authors suggest that 3D-printed pore networks may provide an effective pedagogical tool for teaching multiphase flow, enabling petroleum- and chemical-engineering and geology students to visualize directly often obtuse immiscible-fluid-flow processes within the classroom.
The tool kit is developed in the popular MATLAB language and is executed by graphical user interface. The generation of 3D-printable micromodels from raster datasets comprises three main stages:
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 190419, “Increasing Value Through Digital Transformation: A Case Study From the A Field EOR Asset, Sultanate of Oman,” by S. Holyoak, SPE, A. Alwazeer, S. Choudhury, M. Sawafi, A. Belghache, T. Aulaqi, SPE, S. Bahri, R. Yazidi, A. Yahyai, and K. D’Amours, Petroleum Development Oman, prepared for the 2018 SPE EOR Conference at Oil and Gas West Asia, Muscat, Oman, 26–28 March. The paper has not been peer reviewed.
A thermal asset in Oman is characterized by a large-scale steam-drive/cyclic-steam-soak (CSS) development project, underpinned by extensive data gathering. Efficient execution of data management and analysis within a visualization-intensive, collaborative work environment is critical to success. In this paper, the authors aim to demonstrate that working in this manner enables rapid identification and execution of cost-effective optimization opportunities and risk reduction.
The A West and A East fields are located in the south of Oman. Thick, high net-to-gross sandstones belonging to the Haima Group form the main reservoir unit. The targeted Haima oil is heavy, with viscosities increasing with depth, and reaching up to 400 000 cp close to the oil/water contact (OWC) at the A East field.
Following 25 years of cold production at A West, a development plan addressing thermal redevelopment for both fields was approved in 2009. In A West, a steam-drive pilot began in 2008, whereas, in A East, with its limited production history, CSS was selected for initial production and started in 2014.
Thermal development is characterized by operational complexity and high well counts. Currently, almost 500 wellbores exist in A Field (including sidetracks). The wells are closely spaced, typically 50–100 m at the top reservoir level. Expansion and infill of the development is ongoing, and the well count is increasing steadily. A challenging environment exists for maximizing oil recovery in a safe, manpower-efficient, and cost-effective manner.
On an annual basis, the asset’s decision-based surveillance plan is reviewed, challenged, and updated as required. The execution of this plan, together with incorporation of the field’s reservoir-performance data, translates to a significant amount of diverse information acquired on a daily basis. A combination of highly visual tools and innovative processes is used in a cross-disciplinary work environment to facilitate effective management and analysis of this data.
Data Collection and Transmission
This section provides three examples of current methods used to acquire and transmit data related to A Field’s reservoir integrity, thermal response, and production metrics.
Microseismic. Microseismic wells are being used in other thermal-development projects to monitor for fracturing and fault reactivation. Typically, an array of geophones is cemented into a dedicated wellbore with a data-transmission cable to surface. A microseismic event created by induced fracturing, for example, is detected by the geophones across one or more monitoring wells. Signal processing allows the location, magnitude, and character of the events to be derived. To assess the feasibility of replicating this approach in A Field, additional modeling was carried out, varying the number and placement of the monitoring wells. This showed that the main development areas of A West and A East fields could be covered with six microseismic wells, with three in each field. Furthermore, modeling indicated favorable detection thresholds and event accuracy with this six-well scenario.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 190343, “Challenges and Learnings From Operating the Largest Offshore WAG in the Giant Al-Shaheen Field and Ways To Optimize Future WAG Developments,” by M. Pal, S. Furqan Gilani, and G. Tarsauliya, North Oil Company, prepared for the 2018 SPE EOR Conference at Oil and Gas West Asia, Muscat, Oman, 26–28 March. The paper has not been peer reviewed.
This paper discusses the operation of the largest offshore high-pressure water-alternating-gas (WAG) injection pilot using hydrocarbon (HC) gas, with a gas-injection capacity of approximately 100 MMscf/D, in the giant Al-Shaheen field offshore Qatar. The paper also analyzes the current HC-WAG pilot and optimizes future development scenarios for extending HC-WAG injection to the field scale.
Al-Shaheen WAG Background
As part of the field-development plan, a comprehensive enhanced oil recovery (EOR) screening study was performed that explored the range of available EOR techniques. On the basis of these studies, WAG injection was identified as one of the more-promising EOR options for the field.
Additional studies performed in 2006 and 2007 indicated a large full-field potential for WAG in Al-Shaheen, with an estimated recovery of hundreds of millions of barrels over and above water-flood recovery. Data analysis and intensive simulation work, including both a history match and several forecast sensitivities, were conducted to understand and to estimate WAG potential on Al-Shaheen reservoirs.
The Al-Shaheen WAG process is largely an immiscible process with some multi contact miscibility effects between injectors and producers. Overall, WAG has been a success in the field in terms of seeing incremental oil gains on several patterns. Although physically successful, the project had been challenging operationally. In spite of incremental gains, a number of operational challenges were encountered during the execution of the WAG pilot. These challenges mostly were related to WAG-cycle conversions and operational efficiency of gas-compression systems.
WAG Recovery Optimization
WAG will be a major part of the development of the mature-flank and heavy-oil areas of the field. The areas proposed for WAG are undersaturated with gas at reservoir conditions. Incremental recovery from WAG could be affected by thermodynamic effects caused by large variations in permeability, viscosity, and saturation pressure in the field along with several other variables described in the complete paper.
To analyze the effect of these optimization parameters on incremental oil recovery from WAG, a sector model with varying static and dynamic properties was built (Fig. 1). The properties of the sector model were based on the history-matched model of the neighboring areas. The well spacing was 700 ft, which lies in the middle of the well-spacing ranges of the ongoing WAG pilot wells (500 to 1,000 ft). The WAG sector model was initialized with a range of fixed oil API gravities. Different thermodynamic effects of gas injection have been examined on the sector model. The model is also simulated for different WAG cycle lengths (1/1, 3/3, 6/6, and 12/12), ratios (1:2, 2:1, and 1:3), and slug sizes (1–30 years of WAG). The effects of choking production wells and changes in injection gas composition were also tested on the sector model.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 189810, “Real-Time Completion Optimization of Fracture Treatment Using Commonly Available Surface Drilling and Fracking Data,” by Mohit Paryani, Djamel Sia, Bhavina Mistry, Drew Fairchild, and Ahmed Ouenes, FracGeo, prepared for the 2018 SPE Canada Unconventional Resources Conference, Calgary, 13–14 March. The paper has not been peer reviewed.
The objective of optimizing a fracture design is to spend the least amount of money and get the most productivity out of the reservoir by stimulating and contacting as much reservoir rock as possible. This paper presents a unique work flow that addresses in real time the challenges of perforation and fracture-treatment design while accounting for the lithologic and stress variability along the wellbore and its surroundings.
Surface Drilling Data in Fracturing Design and Analysis
Existing fracturing-design tools often make simplistic assumptions because of a lack of input data. These designs still use layer-cake models and sometimes rely on the data of a nearby well rather than data measured at the considered well. As cost-cutting efforts accelerate in unconventional wells, expecting a log at every well will not be feasible. Because the outcome from the fracturing design heavily depends on specific geomechanical properties, stresses, and surrounding natural fractures, changing the current industry practice of using a nearby well and assuming all subsurface properties to be the same for all stages is imperative. The software used by the authors is able to derive a 3D distribution of the rock properties required as input in the fracturing design. This fracturing-design input available at any well is made possible by using surface drilling data to compute geomechanical logs, pore pressure, stresses, porosity, and natural fractures.
Transforming Drilling Data Into Log Properties. The surface drilling data commonly available on any rig includes weight on bit, rate of penetration, rotational speed, and torque. Transforming this data into valuable input for fracturing design starts by computing the corrected mechanical specific energy (CMSE), which removes frictional pressure losses along the drillstring to obtain accurate estimations at the bit. Confined compressive strength (CCS) is then estimated. When the CMSE and the CCS are estimated correctly, the drilling efficiency is computed. Deviations from expected pore pressures are recognized by comparing a hydrostatic trendline with the drilling-efficiency data.
The methodology to derive pore pressure from drilling data is based on the concept that the energy spent at the bit to remove a unit volume of the rock is a function of the differential pressure to which the rock is subjected while drilling. The differential pressure provides useful information for deriving the pore pressure. Feeding the rock-strength and pore-pressure information to the real-time geomechanical model helps identify the differential stress variability along the wellbore. Other rock mechanical properties also can be estimated using various lithologies derived from rock-strength information.