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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.
Hou, Yuting (PetroChina Changqing Oil Company) | Wu, Yong (PetroChina Changqing Oil Company) | Hu, Xifeng (PetroChina Changqing Oil Company) | Tang, Meirong (Oil & Gas Technology Research Institute of Changqing Oil Company) | Liu, Yuan (Schlumberger) | Zhang, Jie (Schlumberger) | Niu, Li (Schlumberger) | Xu, Wenran (ProTechnics)
The continental depositional environment poses unique challenges for the exploration of unconventional resources. The tight reservoir nature requires horizontal drilling and multistage completion. However, the geologic discontinuity and the geomechanical heterogeneity complicate lateral completion design, fracturing treatment execution, and production analysis. The experience of developing the first two horizontal wells for shale oil exploration in the Ordos basin resulted in observations that link the geology, reservoir, geomechanics, and production behaviors, which can be used for future appraisal and development in similar environments.
In 2014, one exploration well in the south Ordos basin demonstrated that the source rock from the Chang-7-3 formation could produce good light oil, but the tight reservoir needed horizontal drilling and multistage fracturing completion to achieve the production potential. In 2019, two horizontal wells were placed adjacent to each other for appraisal purposes. Due to the unique lacustrine deposition environment of the Chang-7-3 formation, landing the laterals in the target formation proved to be very challenging even with special geosteering tools. For both wells, the net-to-gross ratio is less than expected (51% and 38%), creating significant challenges for the ensuing completion phase. The multistage completion and fracturing were designed with full consideration of the horizontal lateral conditions. Reservoir quality (RQ), completion quality (CQ), and geology quality (GQ) were considered to optimize the completion staging strategy and fracturing plans. Besides the pressure response during fracturing, two additional monitoring and evaluation systems were deployed during the completion phase: microseismic interpretation and chemical tracers. Observations from these three measurements provided valuable information of how the formation responded to the staging strategy, fracturing initiation and diversion, and flowback and production.
Post-fracturing production from both wells met expectations in the testing phase. Additionally, the observations during fracturing and flowback of those two wells provide unique value for better understanding the Chang-7-3 formation. Fracture initiation proved to be feasible only in the lateral sections with proper sand facies where good RQ and CQ were found. Microseismic monitoring showed fracture orientation and planar extension in space. Tracer results revealed where the formation hydrocarbons came from and how the two wells interacted. This case study will have significant influence for future drilling and completion in the Chang-7-3 formation and provide a useful case history for continental shale oil scenarios.
Abstract Perforating cemented casing is a staple for completing wells in every major basin in North America. The objective is to provide a highly conductive pathway between the wellbore and the target formation for both the stimulation and production fluids. New technology, statistical analysis, experimentation and trial-and-error are all used to find the optimal method for creating this pathway. Diagnostics like proppant tracers, downhole cameras, distributed temperature sensing (DTS), distributed acoustic sensing (DAS) and perforation friction pressure analysis can also be used to help evaluate the successes associated with the different methods for perforating. New technology in creating consistent hole perforations in a horizontal wellbore, without the need for mechanical centralization or positioning systems, has recently been developed. This method of perforating employs a specialty shaped charge that allows for more control in the distribution of entry hole diameter (EHD) across a given cluster. This provides operators a more predictable and consistent pathway from the wellbore to the formation. Not only is a consistent hole desirable in a standard multi-cluster stage treatment, but other recent completions trends can also benefit from increased precision in perforating. High density perforating (HDP) is being used in order to create more transverse fractures along the length of the well. A consistent hole allows for more precise estimations of pressure drop across each cluster in these mostly limited-entry or extreme limited entry (XLE) completions. Additionally, near-wellbore (NWB) perf sealing pods are being used to divert treatments from initially open clusters to bypassed or partially open clusters in an attempt to force perf cluster efficiencies higher and distribute stimulation fluids and proppant more evenly. Having a consistent hole for every perforation is ideal in attempting to seal the perforations in the NWB region with a fixed diameter pod. SPE 189900 (Senters, et al 2018) provides more detail on diversion optimization. Engineered completions design is employed in an attempt to selectively perforate rock within a stage with similar mechanical properties to drive stimulated cluster efficiencies higher. Perforating similar rock with a consistent hole shaped charge only stands to improve the chances of distributing the treatment more evenly throughout the clusters. This paper will provide insight into the recent trends in perforating which show an increase in the amount of consistent hole shaped charges versus conventional shaped charges like deep penetrating and large hole. Diagnostic data accompanies entry hole diameter statistics and friction pressure calculations for the consistent hole shaped charges in order to demonstrate how they differ from conventional shaped charges. Finally, proppant tracer diagnostics will highlight several case studies where consistent hole shaped charges or other recent perforating methods were employed.
Abstract This paper discusses a well-to-well spacing test on a 5 well pad in the Utica Shale that was stimulated with a unique stage sequencing plan. The stage sequencing plan provides an improved understanding of the way that fracture growth can be influenced by subsurface pressure differentials created by newly fractured, shut-in and depleted wells. Chemical (water) tracers and oil tracers were pumped into the center well of the 5 well pad. The non-traced wells on the pad, along with 2 wells on an adjacent pad, were all sampled during flowback and production. The samples were analyzed for the presence of oil and chemical tracers to determine the extent and degree of well-to-well communication. Additionally, surface microseismic data was collected and used to further assist in the study of the fracture growth. The tracer communication and microseismic data were represented together in a 3D visualization of the well pads. Generally, the tracers and microseismic events show that there is more extensive fracture growth from a treatment well to offsetting wells when there is no hydraulic pressure barrier between them. Better fracture containment and symmetry was observed on stages that were bounded on both sides by wells that were just fractured. Data from the study show that proper sequencing of the completions can mitigate the tendency for fractures to preferentially grow towards depleted wells. The study will therefore illustrate the value of tracer and microseismic data for understanding additional or new knowledge about multi-well pad stage sequencing and its role in fracture growth, and overall future well planning strategy.
The Granite Wash continues to be a prolific hydrocarbon producer, with over 1600 wells drilled during the last 10 years. During 2012 and 2013 an extensive development program was initiated by one operator in which 144 wells were drilled and completed with multi-stage hydraulically stimulated horizontal wells. Many of these wells utilized various types of completion diagnostics to: (1) evaluate vertical and horizontal communication within the Granite Wash, (2) identify potential horizontal loading problems and (3) diagnose long-term fracture fluid movement.
This paper reviews more than two years of water-based frac fluid tracer data. It details how the individual tracers were used to quantify communication between various layers of the Granite Wash and between nearby completed offset wells. Also, toe stage frac fluid recoveries were compared to identify wells that appeared to be constrained. Data will be presented documenting specific cases of inter-well and inter-zonal communication. This will include both offset wells that had been on production prior to the fracturing treatment and offset wells that had been recently drilled.
Extended sampling of individual fluid tracers can be an extremely useful tool in explaining production anomalies as they occur. On this project, the operator was able to identify the source of production changes and determine the best well intervention technique to economically increase production.
The Texas/Oklahoma Granite Wash is composed of a series of heterogeneous arkosic sandstones and conglomeratic sediments that were deposited into the basin during the denudation of the Amarillo Uplift. The resulting deposits represent a stratigraphic inversion of the original uplift strata. Granite Wash detrital grains were derived from granite, rhyolite, gabbro, sandstone, chert, limestone, and dolomite source rocks; this is evidenced by the amount of quartz, K-feldspar, plagioclase feldspar, calcite, chert, and rock fragments within these sediments. These Granite Wash zones were deposited northward into the Anadarko Basin as fan delta and submarine fan accumulations. The primary reservoir developments in this area are situated within channelized deposits of submarine fan complexes. Figure 1 shows the general geographic location of the Granite Wash play.
Copyright 2011, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Hydraulic Fracturing Technology Conference and Exhibition held in The Woodlands, Texas, USA, 24-26 January 2011. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract Fluid and proppant tracers and other simple measurements in returning load water flow back can be very useful in helping to describe fracture development in shales; including such parameters as fracture complexity, frac conductivity, height growth, frac barrier effectiveness, well-to-well and frac-to-frac interference, water entry points and general fracturing execution. For most engineers, flow back ion charts have often had little relevance beyond estimating frac stage flow back activity; however, combining fluid tracer information with low-level gamma emitting proppant tracers, microseismic, simple salinity measurements and water return rate can help describe fracture and formation behaviors that lead to faster optimization of fracturing design and application. This paper will use fluid and proppant tracer results from over a hundred shale frac stages in horizontal wells along with other measurements of frac flow back and blend them with microseismic, frac pumping records, production logging and production results to build a framework for better analysis of frac flow back. Introduction There are many data gathering and generating methods for optimization of well performance; however, much of the well data in an average well file is not used to optimize well performance. The reasons may be numerous, but some of the most common causes may be a lack of understanding of how to compare and use the data and how to assess the accuracy of information that is less than a certainty.
Abstract Chemical gas tracers have been used in gas flood projects to evaluate interwell communications, formation heterogeneity, channeling, and to calculate volumetric sweep efficiency. For the first time, these tracers are used to evaluate the extent of fracture communication with offset wells and also to evaluate zonal communication between four hydraulically fractured reservoirs. The four horizontal wells are drilled and completed in Berea, Chagrin, Lower Huron Siltstone, and Lower Huron reservoirs. Each well was individually fractured with nitrogen gas in nine stages. A different chemical gas tracer was injected in each of the horizontal wells during the fracture stages with the carrier gas. Upon the completion of each fracture treatment, the well was shut-in to frac the next well. Upon the completion of the last fracture treatment, the well was shut-in for the reservoir pressure to stabilize before all four wells were put back on production. Flowback gas samples were collected at the wellhead for tracer detection analysis and hence flowback analysis. In addition, produced gas samples were collected at the offset wells for gas tracer detection to evaluate the extent of the fractures, interwell communication and formation heterogeneity. The results of flowback, zonal communication and extent of fracturing are presented in detail.
Abstract A combination of multiple down hole gauges and dual density / tracer logs were utilized to quantitatively evaluate distribution of fluid and proppant across a long perforated interval separated in two lobes and to quantify the annular pack percentage across the entire completion interval during a deepwater frac pack treatment in GoM. It was important to evaluate the achievement of an effective fracture in both lobes and define the annular pack percentage across the entire completion interval to be able to produce the well to its potential. This technique quantitatively evaluated the entire frac pack process and determined screen out events in separate lobes and annular pack efficiency. The analysis also defined the dynamics of the treatment fluid and proppant slurry movement during the frac pack pumping operation and their final placement. Several expected as well as unexpected conclusions and observations were identified. In summary, the diagnosis indicated that higher percentage of treatment fluid and proppant was received by the upper sandstone lobe. The exact proppant concentration at lower lobe screen out was identified. A baseline pre-pack value was established, which allowed the annular pack percentage to be calculated across the entire interval. It also provided detailed information on the sequence of events during washout at the crossover tool. All of these allowed the operator to confidently maximize deliverability from the subject well, which is currently producing 110 MMcfd. The results from this case history and the technique described should result in a step change in frac pack evaluation. Quantitative evaluation eliminates any doubts about the effectiveness of the annular pack and allows operators to produce their assets at maximum deliverability. Additionally, it assists future completion designs and type selection.
Abstract Secondary recovery is a process in which reservoir fluid is mobilized and moved from an injection well toward a production well. The success of this process greatly depends on the knowledge of reservoir continuity and uniformity, in terms of fluid transmissibility, and how much of the reservoir fluid volume can be contacted by the injection fluid. In any water/gas flood injection project, fluid channeling through mini-fractures, faults, and high permeability streaks results in problems such as poor reservoir sweep efficiency and low hydrocarbon recovery. Therefore, knowledge of direct communication between the injection and production wells as well as an understanding of formation heterogeneity can be of great help to overcome these problems. While techniques such as seismic, mapping geological deposition and reservoir simulation provide valuable information about the feasibility of secondary recovery projects, tracer testing is the only available method that provides valuable information on direct communication, flow-path, and formation heterogeneity across the injection and production wells. This paper presents a detailed review of chemical tracer applications in IOR with a supportive case history from a water-flood field. The paper also presents interpretation and discussion of the results on direct communication identification, formation heterogeneity evaluation, and swept pore volume calculation.
Abstract Chemical frac tracing is used to evaluate flowback and cleanup efficiencies for eight different wells in a field located Central America. The technique utilizes a family of unique, environmentally-friendly, fracturing fluid compatible chemical tracers to quantify segment-by-segment recovery for individual fracturing treatments and stage-by-stage recovery for multi-stage fracturing treatments. Each well was traced with a number of different tracers during hydraulic fracturing. Upon flowback, samples were collected and analyzed for tracer concentrations. With the use of the mass balance method, total flowback and flowback efficiency for each stage were calculated. Production for each well was closely monitored for three years. This paper presents in-depth details relating short-term total flowback and fluid stage-by-stage flowback efficiencies to the long-term post-frac performance. Introduction Chemical Frac Tracers. Chemical frac tracers, CFT's, are used to precisely calculate flowback and hence flowback efficiency and to evaluate fracture cleanup. Various chemical tracers with unique chemical characteristics are mixed at a known concentration and injected according to a predetermined design throughout individual frac fluid segments, such as the pad and the proppant laden fluid stages. These chemical tracers do not react with each other, the formation or the tubular. They do not degrade with temperature or time, do not self-concentrate, and do not react with frac fluids. These tracers are detectable at low concentrations of 50 ppt (parts per trillion). They are also environmentally safe to handle, pump downhole and to dispose of. They are soluble in water, and unlike polymers, do not concentrate upon leakoff. The CFT's are injected into the treatment fluid segments at a concentration of 1 ppm with a positive-displacement peristaltic pump on the low-pressure side of a frac pump. At these extremely low concentrations, the CFT chemicals have been thoroughly proven to have no effect on the stability or performance of the fracturing fluids into which they are injected. Upon commencing flowback, samples of the flowback fluid are collected every 10 min to 12 hr via a sampling valve at the surface prior to the flowback fluid entering a dedicated flowback tank (which is used to measure the cumulative fluid flowback volume recovered at the time each flowback sample is collected). Samples are collected for a minimum of 48 hr and for a realistic maximum of 30 days. The collected samples are then analyzed using a sophisticated analytical procedure which is capable of concurrently quantifying all of the CFTs down to the 50 ppt (parts per trillion) level. These analysis results are then normalized and/or plotted vs. elapsed flowback time. The mass of each CFT recovered in a given time period together with the total recovered fluid flowback volume for that same time period are used to calculate fluid flowback efficiencies by employing the mass balance principle. The resulting segment-by-segment fluid recovery profiles are then used to help characterize the effectiveness of cleanup and to make recommendations regarding potential improvements in treatment fluid cleanup that might be obtained by changes in the treatment fluid chemistry (e.g., type of crosslinker, polymer loadings, breaker loadings, gel stabilizer loadings, etc.), as well as proppant scheduling schemes, flowback procedures, etc. Background. Although fluid flowback is an important part of a fracture treatment, it has been overshadowed by proppant flowback in recent years. The detrimental effects of reduced fracture conductivity as a result of poor flowback and cleanup are well documented. Most research has focused on the effects of using improper flowback procedures on well performance. The associated effects are proppant movement into the wellbore, proppant crushing at or near the wellbore, and fracture plugging.