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Abstract In previous frac designs, proppant tracer logs revealed poor proppant distribution between clusters. In this study, various technologies were utilized to improve cluster efficiency, primarily focusing on selecting perforations in like-rock, adjusting perforation designs and the use of diverters. Effectiveness of the changes were analyzed using proppant tracer. This study consisted of a group of four wells completed sequentially. Sections of each well were divided into completion design groups characterized by different perforating methodologies. Perforation placement was primarily driven by RockMSE (Mechanical Specific Energy), a calculation derived from drilling data that relates to a rock's compressive strength. Additionally, the RockMSE values were compared alongside three different datasets: gamma ray collected while drilling, a calculation of stresses from accelerometer data placed at the bit, and Pulsed Neutron Cross Dipole Sonic log data. The results of this study showed strong indications that fluid flow is greatly affected by rock strength as mapped with the RockMSE, with fluid preferentially entering areas with low RockMSE. It was found that placing clusters in similar rock types yielded an improved fluid distribution. Additional improved fluid distribution was observed by adjusting hole diameter, number of perforations and pump rate.
Kebert, Brent (Colorado School of Mines) | Almulhim, Abdulraof (Colorado School of Mines) | Miskimins, Jennifer (Colorado School of Mines) | Hunter, William (Ovintiv Inc) | Soehner, Gage (Ovintiv Inc)
Abstract Successfully treating each cluster within a hydraulic fracturing stage is a key objective for "plug-n-perf" well completions. Most operating companies would agree that the main underlying desire for a successful completion is related to future production capability. In unconventional reservoirs, propped and conductive hydraulic fractures are the primary completion result that drives production and reserve recovery. When designing a treatment, the spacing of clusters is critical to optimizing production and reserve recovery parameters, and therefore, even proppant distribution across a single stage delivers a well the greatest potential for optimized production performance. Diverting the fracturing fluid and proppant evenly across the clusters in a stage allows the greatest opportunity for each cluster to produce equally and drain the associated reservoir volume. Generating equal, producing fractures across a horizontal wellbore is a difficult problem that operators are still trying to solve. This work models the fluid and proppant distribution across a field-scale, 250-ft long, horizontal hydraulic fracturing stage, replicating realistic field conditions. By utilizing computational fluid dynamics (CFD), this paper investigates the effected proppant distribution results from a fracturing stage mimicking the presence of both a leaking plug and the impacts of stress shadowing. The proppant concentration throughout the wellbore, along with internal wellbore pressure and velocity, are also reviewed to gain an understanding of the effect of the field conditions. Additionally, this paper illustrates the effect of different proppant "ramping" conditions during the fracturing stage. Proppant ramping schedules can be smooth or sharp when increasing proppant concentration, which alters the proppant concentrations throughout the wellbore and associated perforation clusters. Unanticipated alterations of the proppant concentration within the wellbore can lead to early screenouts. Gaining a better understanding of the proppant distribution and concentration inside the wellbore can lead to improved designs of hydraulic fracturing completions.
Troubleshooting and solving separation problems takes a combination of analytical tools, experience, and a knack for investigation. Asking the right questions for information and then synthesizing that information can consume a significant amount of time and resources. However, once the problem is solved, some key messages stay with you for solving future issues. This article will discuss several examples of troubleshooting separation problems and the main lesson learned from each one. The applications cover issues related to solids, droplet shearing, maldistribution, and instrumentation.
This paper presents a data set involving the pumping of multiple, unique chemical tracers into a single Wolfcamp B fracture stage. The goal of the tracer test is to improve understanding of the flowback characteristics of individually tagged fluid and sand segments by adding another layer of granularity to a typical tracer-flowback report. The added intrastage-level detail can provide insights into fracture behavior in shale-reservoir stimulation by looking at individual fluid-segment tracer recoveries. Operators have relied upon high- intensity completion designs that include a combination of high proppant volumes, increased perforation-cluster density, and smaller-mesh-size proppants. These designs aim to create a complex fracture network and increase the contact area with shale rock.
Aftab, Muhammad (ADNOC Onshore) | Swain, Ashis (Al Yasat Petroleum Operations LLC) | Sultan, Mir (ADNOC Onshore) | Al Blooshi, Abdulla (Al Yasat Petroleum Operations LLC) | Al Shamsi, Mohamed (Al Yasat Petroleum Operations LLC) | Mingsheng, LV (Al Yasat Petroleum Operations LLC) | Abu Snaineh, Bashar (ADNOC Onshore) | Al Mansoori, Sara (Al Yasat Petroleum Operations LLC)
Generally, appraisal wells are drilled to reduce uncertainty. However, occasionally reserves uncertainties may increase in a heterogeneous carbonate reservoirs specially challenging stratigraphic limit of reservoir facies. Under such circumstance, sometime operators rethink of further investment in the field development when in-place volumes are marginal.
The objective of the study is to present how we achieved well design modification and test strategy in a dynamic environment. Optimal well test design, execution and analysis can help mitigate major uncertainties, which were not considered during initial planning phase
The subject appraisal well was drilled as a vertical hole in an up dip direction to the first appraisal well. However, Open Hole (OH) and mud log data indicated the reservoir to be tight and in some portion dominated by water flow during sampling even though clear hydrocarbon presence observed in core chips and cuttings analysis. After detailed studies of the available data, a decision was taken to horizontalize the well towards first appraisal well. While drilling, geological barriers were encountered as indicated by the presence of different fluids in the horizontal section. Variable fluid presence (water and oil) posed a challenge with respect to well completion and testing. This paper describes the process of completing the well in an evolving complicating situation and how successful well test design and execution helped to mitigate the uncertainties.
OH Logs, Wire Line Formation Tester (WFT) and test data from the studied and existing wells in the area were used to design the well test and interference with first appraisal well in an evolving situation, which is not typically faced in well operations. Hence, the results obtained provide an additional information that helped to conclude variable fluid distribution and its dynamic connectivity to the first appraisal well.
Well was completed followed by test as designed and Production Logging Testing (PLT) was conducted to define reservoir contribution. Post well test analysis and comparison with existing WFT and test data from existing well helped to conclude results and address the uncertainties.
This paper summarizes the design process, challenges faced in an unexpected variable fluid distribution in the horizontal section and accordingly how well test analysis was performed to conclude the results that helped to take optimal investment decision for the development of this marginal reservoir.
Kumar, Sikandar (Skolkovo Institute of Science and Technology) | Burukhin, Alexander Alexandrovich (Skolkovo Institute of Science and Technology) | Cheremisin, Alexey Nikolaevich (Skolkovo Institute of Science and Technology) | Grishin, Pavel Andreevich (Skolkovo Institute of Science and Technology)
Abstract As the production of hydrocarbons from the carbonate reservoir increases, there is a necessity to enhance oil recovery methods to increase recovery factors and improve the economic efficiency of field development. The knowledge of wettability's role and fluid distribution at the pore scale is required to comprehend the mechanisms for oil displacement from porous media. The X-ray computed micro-CT technology provides opportunities to study the complex fluid displacement process at the pore level. This work discusses wettability restoration in carbonate cores and its effect on fluid distribution in porous space. Wettability restoration refers to restoring the original wettability of the core after extraction. We investigate wettability change and two-phase fluid distribution at pore-scale with the help of micro-CT technique along with Amott spontaneous imbibition methods. The Amott spontaneous imbibition experiments performed on the core under ambient pressure. The micro-CT experiments conducted for steady flow core flooding experiments on harsh cleaned cores. The three-dimensional images acquired for dry core, core saturated with brine and kerosene followed by oil injection. For better visualization of the fluid-fluid and fluid-rock surface and to remove voxel artifacts, iodo-octane is mixed with oil with 10 % wt/wt. The experiments allow us to envisage the structures of fluid in each phase during the displacement of fluid in carbonate rocks with high resolution (3 μm/voxel). The novelty of this approach lies in efficiently capturing the CT images of the fluid distribution and its influence on wettability during the "core-aging" procedure and validating the results of it with the Amott imbibition wettability index. The initial wettability of harsh cleaned carbonate cores was identified as water-wet compare to mixed wettability for mild cleaned carbonates. Nevertheless, all the samples become strongly oil-wet regardless of the cleaning methods after long-term saturation with crude oil. The X-ray CT technique revealed the fast evolution of contact angle of brine corresponding the wettability changes to strong oil-wet after contact with crude oil under the reservoir conditions.
This article, written by JPT Technology Editor Judy Feder, contains highlights of paper IPTC 19807, “A New Downhole System for Real-Time Reservoir-Fluid-Distribution Mapping: E-REMM, the Eni Reservoir Electromagnetic Mapping System,” by Franco Bottazzi, Paolo Dell’Aversana, and Claudio Molaschi, SPE, Eni, et al., prepared for the 2020 International Petroleum Technology Conference, Dhahran, Saudi Arabia, 13-15 January. The paper has not been peer reviewed. Copyright 2020 International Petroleum Technology Conference. Reproduced by permission. This paper presents the basic concepts and architecture of the Eni Reservoir Electromagnetic Mapping (E-REMM) borehole electromagnetic (EM) mapping system that integrates borehole EM methodology with surface EM methods to provide real-time mapping of reservoir-fluid distribution during production or injection. By helping well teams know how distribution of hydrocarbons and water changes over time and space, the system addresses a fundamental requirement for managing the reservoir to maximize the recovery factor, optimize production, and reduce associated costs. Introduction Several approaches are currently used to map hydrocarbons and other fluids in the reservoir in real time with variable sensitivity, differences in effectiveness, and a wide range of costs. Among the various approaches, EM and electric methods show a high benefit-to-cost ratio and a high sensitivity to the resistivity contrast between oil-saturated and brine-saturated reservoir rocks. These methods can estimate variations in fluid properties at reservoir depth in a distance range of hundreds of meters, although the spatial resolution decreases significantly with the distance between sources and receivers. Furthermore, combining multiple layouts in boreholes and at surface can improve the effectiveness of EM and electric methods significantly while increasing their spatial resolution. The integrated system discussed in the complete paper allows multiscale EM prospecting and deep investigation in a large 3D volume of rocks between multiple wells and surface.
This paper presents the basic concepts and architecture of the Eni Reservoir Electromagnetic Mapping (E-REMM) borehole electromagnetic (EM) mapping system that integrates borehole EM methodology with surface EM methods to provide real-time mapping of reservoir-fluid distribution during production or injection. By helping well teams know how distribution of hydrocarbons and water changes over time and space, the system addresses a fundamental requirement for managing the reservoir to maximize the recovery factor, optimize production, and reduce associated costs. Several approaches are currently used to map hydrocarbons and other fluids in the reservoir in real time with variable sensitivity, differences in effectiveness, and a wide range of costs. Among the various approaches, EM and electric methods show a high benefit-to-cost ratio and a high sensitivity to the resistivity contrast between oil-saturated and brine-saturated reservoir rocks. These methods can estimate variations in fluid properties at reservoir depth in a distance range of hundreds of meters, although the spatial resolution decreases significantly with the distance between sources and receivers.
Stepanov, Vladimir (Schlumberger) | Ramondenc, Pierre (Schlumberger) | Mhiri, Adnene (Schlumberger) | Abdrazakov, Dmitriy (Schlumberger) | Burdin, Konstantin (Schlumberger) | Konysbayev, Yerzhan (Schlumberger) | Slobozhaninov, Alexander (Schlumberger) | Amangeldiyev, Anvar (Schlumberger) | Kinnear, Campbell (Tengizchevroil) | Sultanov, Bauken (Tengizchevroil)
Abstract It is becoming more common for operators around the world to use alleged conformance control completions as a means of managing inflow zones and controlling production. When this type of completion is introduced in a field, it is extremely important to analyze its effectiveness at very early stages of the project to achieve maximized zonal contribution together with proper compartmentalization in current and subsequent completions, since this will have a significant impact on the future life of the entire field. A thorough analysis should include understanding zonal isolation before and after acid stimulation, fluid distribution inside the compartments during the treatment, and confirmation of completion integrity. Analyzing completion performance by introducing additional downhole monitoring systems or devices is costly and is more appropriate for the long term. Another option, surveillance with wireline technology, may not provide definite conclusions due to limited acquisition extent. Alternatively, coiled tubing (CT) can provide a fit-for-purpose integrated solution to data acquisition and analysis challenge. The proposed approach uses distributed temperature sensing technology along with real-time data streaming capabilities to provide an instantaneous insight on wellbore dynamics, thus enabling informed decisions on treatment optimization, as well as yielding reliable information on interzonal communication. This study is based on a success story of intervening with CT on 10 wells, with a total of 40 compartments in a carbonate reservoir in the Caspian region. Distributed temperature evolution models are used to build a signature library characteristic of specific flow events in the wellbore. The study consists of distributed temperature surveys lasting from 30 minutes to 6 hours that were acquired before and during the acid stimulation of each conformance compartment. Unique temperature features are identified in specific flow events, such as communication between compartments, loss of completion integrity, and effective stimulated area determination, to name a few. Those events are hypothesized and corroborated using downhole point measurements. A significant finding is that communication between zones occurs through several possible paths (i.e., through the formation/matrix or via the completion). The stimulation strategy can be modified accordingly, leveraging downhole data to maximize completion efficiency. This combination of transient distributed temperature and point measurement data provides an insight into wellbore and reservoir flow dynamics and facilitates an optimized stimulation strategy.
Haustveit, Kyle (Devon Energy) | Elliott, Brendan (Devon Energy) | Haffener, Jackson (Devon Energy) | Ketter, Chris (Devon Energy) | O'Brien, Josh (Devon Energy) | Almasoodi, Mouin (Devon Energy) | Moos, Sheldon (Devon Energy) | Klaassen, Trevor (Devon Energy) | Dahlgren, Kyle (Devon Energy) | Ingle, Trevor (Devon Energy) | Roberts, Jon (Devon Energy) | Gerding, Eric (Devon Energy) | Borell, Jarret (Devon Energy) | Sharma, Sundeep (Devon Energy) | Deeg, Wolfgang (Formerly Devon Energy)
Over the past decade the shale revolution has driven a dramatic increase in hydraulically stimulated wells. Since 2010, hundreds of thousands of hydraulically fractured stages have been completed on an annual basis in the US alone. It is well known that the geology and geomechanical features vary along a lateral due to landing variations, structural changes, depletion impacts, and intra-well shadowing. The variations along a lateral have the potential to impact the fluid distribution in a multi-cluster stimulation which can impact the drainage pattern and ultimately the economics of the well and unit being exploited. Due to the lack of low-cost, scalable diagnostics capable of monitoring cluster efficiency, most wells are completed using geometric cluster spacing and the same pump schedule across a lateral with known variations.
A breakthrough patent-pending pressure monitoring technique using an offset sealed wellbore as a monitoring source has led to advancements in quantifying cluster efficiencies of hydraulic stimulations in real-time. To date, over 1,500 stages have been monitored using the technique. Sealed Wellbore Pressure Monitoring (SWPM) is a low-cost, non-intrusive method used to evaluate and quantify fracture growth rates and fracture driven interactions during a hydraulic stimulation. The measurements can be made with only a surface pressure gauge on a monitor well.
SWPM provides insight into a wide range of fracture characteristics and can be applied to improve the understanding of hydraulic fractures in the following ways: Qualitative cluster efficiency/fluid distribution Fracture count in the far-field Fracture height and fracture half-length Depletion identification and mitigation Fracture model calibration Fracture closure time estimation
Qualitative cluster efficiency/fluid distribution
Fracture count in the far-field
Fracture height and fracture half-length
Depletion identification and mitigation
Fracture model calibration
Fracture closure time estimation
The technique has been validated using low frequency Distributed Acoustic Sensing (DAS) strain monitoring, microseismic monitoring, video-based downhole perforation imaging, and production logging. This paper will review multiple SWPM case studies collected from projects performed in the Anadarko Basin (Meramec), Permian Delaware Basin (Wolfcamp), and Permian Delaware Basin (Leonard/Avalon).