The expansion of unconventional resources development has placed emphasis on better understanding of hydraulic fracturing stimulation effectiveness and the area of pay affected by the fracture treatment to optimize well spacing and improve completion and stimulation effectiveness. Existing fracture diagnostic methods such as microseismic monitoring and tiltmeters do not provide information about fracture connectivity to the wellbore. In this paper, we present a chemical tracer flowback based fracture diagnostic and analysis methods to estimate the fractional contribution of each created fracture stage, which is open and connected to the wellbore to help improve field development strategies and provide valuable information on optimal well paths for future drilling and development. The findings out from the stage production contribution profiles using the chemical tracer technology allows engineers to improve stimulation efficiency in multistage hydraulic fracturing horizontal wells applications for completion optimization and production enhancement. Two case histories are presented in which the chemical tracer technology was applied to two horizontal wells. The results of the chemical tracer analysis were correlated to production data, reservoir parameter and other diagnostic tests. The resultant findings from the analysis help evaluate completion and stimulation effectiveness and determine the extent of inter-well connectivity of the fracture network and then used to optimize future completions in the region.
Thomas, Gawain (Aramco Services Company) | Ow, Hooisweng (Aramco Services Company) | Chang, Sehoon (Aramco Services Company) | Shi, Rena (Aramco Services Company) | Wang, Wei (Aramco Services Company) | Chen, Hsieh (Aramco Services Company) | Poitzsch, Martin (Aramco Services Company) | Shateeb, Hussain (Saudi Aramco) | Abdel-Fattah, Amr (Saudi Aramco)
A novel barcoded advanced tracers system has been developed and field-validated in a hydrocarbon reservoir. With a detection scheme that supports automation, this cost-effective tracers system is designed to enable potentially ubiquitous long-term full-field injections in the interest of using the high fidelity tracer data to increase the oil recovery factor through improved optimization of the water injection and oil production.
Our Advanced Tracers system uses real-time chromatographic separation and optical detection to achieve ultra-low limits of detection (LOD) at 1 part per billion (ppb) or better. Such low LOD facilitates small injection quantities, making full field deployment of Advanced Tracers cost-effective compared to state-of-the-art interwell tracers. Additionally, the detection strategy that enables automation of the analysis process for real-time tracer detection is outlined, paving way for minimal manual sample collection and work-up.
Results on recently field-validated real-time optically-detectable tracers in a hydrocarbon reservoir, detectable at ultra-low LODs, are described. This is achieved even in the presence of background oil by means of an intrinsically oil-blind detection method. The material exhibits high mobility in high-salinity high-temperature carbonate reservoirs, with tracer breakthrough successfully detected at concentrations of less than 1 ppb using chromatographic separation followed by an optical detection method. The novel methodology as outlined highlights its simplicity, safety and cost-effectiveness relative to current practices in the field.
Fluorobenzoic acid based tracer technology requires chemical derivatization of the samples for ultra-low detection limits in a GC-MS. Our novel tracer detection strategy omits the need for chemical derivatization. In addition, it enables a compact, portable, optical-based automated wellsite detection system to be used in the field, with tens of unique barcodes possible. These innovative steps are keys to near real-time tracer detection in the field, realizing one of the intelligent oil field monitoring and the reservoir management applications.
When it came to decide where to collect a critical sample of fractured rock, a new method for turning microseismic data into a heat map designed to display the most intense fracturing activity was considered. Partitioning interwell tracer tests (PITTs) have been used to estimate remaining oil saturations (ROSs) during waterflooding. This paper reviews the design and implementation of a full-field interwell tracer program for a giant onshore oil field in Abu Dhabi. The surge in unconventional completions has created a substantial accumulation of previously hydraulically fractured wells that are candidates for hydraulic refracturing. Rising demand for flowback technologies to reduce uncertainties is leading to the creation of more hydrocarbon and water tracers.
AlAbbad, Mohammed A. (Saudi Aramco) | Sanni, Modiu L. (Saudi Aramco) | Kokal, Sunil (Saudi Aramco) | Krivokapic, Alexander (Institutt for Energiteknikk) | Dye, Christian (Institutt for Energiteknikk) | Dugstad, Øyvind (Restrack) | Hartvig, Sven K. (Restrack) | Huseby, Olaf K. (Restrack)
The single-well chemical-tracer test (SWCTT) is an in-situ test to measure oil saturation, and has been used extensively to assess the potential for enhanced oil recovery (EOR) or to qualify particular EOR chemicals and methods. An SWCTT requires that a primary tracer be injected and that a secondary tracer be generated from the primary tracer in situ. Typically, a few hundred liters of ester is injected as primary tracer, and the secondary tracer is formed through hydrolysis in the formations. The ester is an oil/water-partitioning tracer, whereas the in-situ-generated alcohol is a water tracer. During production, these tracers separate and the time lag of the ester vs. the alcohol is used to estimate oil saturation in the near-well region.
In this paper, we report a field test of a class of new reacting tracers for SWCTTs. In the test, approximately 100 cm3 of each of the new tracers was injected and used to assess oil saturation. In the test, ethyl acetate (EtAc) was used as a benchmark to verify the new tracers. This paper reviews the design and implementation of the test, highlights operational issues, provides a summary of the analyzed tracer curves, and gives a summary of the interpretation methodology used to find oil saturations from the tracer curves. Briefly summarized, we find the Sor measured by each of the novel tracers to compare with that from a conventional SWCTT. To validate stability and detectability of the tracers, a mass-balance assessment for the new tracers is compared with that of the conventional tracers.
A benefit of the new tracers is the small amount needed. Methodological advantages resulting from using small amounts include the possibility to inject a mix of several tracers. Using several tracers with different partitioning coefficients enables probing of different depths of the reservoir. In addition, the robustness of SWCTTs can be increased by using several tracers, with different reaction rates and temperature sensitivity. The field trial also demonstrated that the new tracers have operational advantages. One benefit is the possibility to inject the new tracers as a short pulse of 10 minutes. Other benefits are that the small amounts needed reduce operational hazards and ease logistical handling.
Several tools and techniques exist to understand distributions of reservoir properties. Interwell tracer testing is one of the most common methods to obtain reservoir information from the amount of tracer produced. The capacitance/resistance model (CRM) is an analytical tool to estimate connectivity between producer/injector pairs from historical rates and, when available, bottomhole-pressure data in waterfloods. Because the CRM is a physically based, simple input/output model, its combination with tracer testing can provide insight into reservoir features.
To enable the CRM application to tracer flow, we incorporated tracer models, based on miscible-displacement theory, into the CRM. Reservoir properties are estimated as a result of the model fitting to produced-tracer data. In this paper, we present three tracer models: a dispersion-only (short-range autocorrelation) model, a Koval (long-range) model, and a combination of the two. To incorporate the tracer models into the CRM, we used two methods, serial fitting (CRM then tracers) and simultaneous fitting (CRM and tracers).
We applied these techniques to tracer data from 10 injectors and 10 producers of the Lawrence Field. Results suggest that interwell connectivity obtained from the CRM is in good agreement with the observed peak-tracer concentrations. All tracer models are capable of giving a good fit in most of the cases. After comparing the tracer models, we determined that the combined model can represent a tracer flow better than the other two models alone. We also found that the simultaneous-fitting method gives the best fit to total producer-rate data and tracer data. Simultaneous fitting mitigates the nonuniqueness of the fits, leading to an improvement of tracer matching. The reservoir properties obtained in this study (Koval factor and dispersion coefficient) also were analyzed and compared with those from previous measurements.
Kopp, Jeff (Reveal Energy Services, Inc.) | Kahn, Charles (Reveal Energy Services, Inc.) | Allen, Charlee (Chaparral Energy, Inc.) | Huchton, Jake (Chaparral Energy, Inc.) | Robinson, Clark (Chaparral Energy, Inc.) | Coenen, Erica (Reveal Energy Services, Inc.)
This paper discusses a STACK (Sooner Trend Anadarko Basin Canadian and Kingfisher Counties) case study that determined the effectiveness of different diversion techniques, including pods, sand ramps with sand slugs, rate cycling, and utilization of the completions order to control fracture growth. A secondary goal of this study was to evaluate the suitability of pressure-based fracture maps and oil and water phase tracers in monitoring diverter effectiveness.
Effectiveness of a given diverter technique and diverter drop was evaluated using the two techniques on a 3-well pad. The three wells were completed using a combination of: 4 pods per treatment interval 6 pods per treatment interval 8 pods per treatment interval high-volume proppant loading per treatment interval
4 pods per treatment interval
6 pods per treatment interval
8 pods per treatment interval
high-volume proppant loading per treatment interval
The effectiveness of the diverter drop was evaluated using each of the diagnostic techniques listed above. The pressure-based fracture analysis uses the pressure response recorded in an isolated stage in the monitor well to compute fracture geometry and the rate of growth of the fracture dimensions. The effectiveness of a given diverter drop is classified into one of four possible categories: stop dominant fracture growth, impede dominant fracture growth, no impact on growth of dominant fracture and accelerate the growth of dominant farcture. These results were then compared with the analysis from oil and water phase tracers and treatment pressure analysis.
Successful (effective) diversion was observed on 82 % of the stages with pods compared to 64% successful diversion where sand ramps were used. In addition, stages using 8 pods for diversion had a 15% reduction in average fracture half-length compared to stages using 4 pods. Fracture height was better controlled through the order of completions of the stages between 3 wells. Completing the middle well in the upper part of the zone ahead of the two outer wells in the lower part of the zone, controlled the vertical height growth of the two outer wells.
The offset pressure-based analysis proved to be as effective in accurately diagnosing the diverter effectiveness and provided a significant cost and timing advantage compared to other diagnostic techniques.
Operators working with multiple stacked-pay reservoirs are challenged to optimize economic returns through their completion designs - not only in regards to horizontal well spacing, but also with vertical well spacing. Many of the popular Texas and New Mexico Wolfcamp formation sections exceed 1,000 feet in thickness and contain multiple hydrocarbon-rich benches. These benches and associated strata are complex mixtures of heterogenic geological factors such as weak/strong structural interfaces between facies, open/healed natural fractures, unpredictable fluid and pressure regimes, along with other lithological variables. Companies wrestle with the optimization of maximum hydrocarbon recovery within ever-present economic constraints when developing reservoir targeting strategies.
This case study used multiple solid, oil-soluble tracers (OSTs) as an aid in reservoir characterization to determine optimal landing zones in the two unique Wolfcamp formations. This was accomplished by monitoring OST recovery data produced from grouping frac stages and reservoir zones over a 435 sampling day period. The two wells in this case study were intentionally drilled highly toe-up in order to cross all the potentially productive areas in two separate Wolfcamp benches; all stages were completed with the same stimulation design.
The dynamics of the OST recovery provided insight into the variability of reservoir productivity within the Wolfcamp. Particular layers in the two wells exhibited initially high but transient OST recoveries, while other zones produced OSTs longer and more consistently. Using granular level tracer data in conjunction with other geoscience information, the operator was able to identify the formation layers having the highest potential for optimal production economics. This new methodology not only provided single-well placement optimization, but also important insights for future completions.
In the Midland Basin, infill wells have high potential of experiencing well-to-well fracture interference or "frac hits". Rock stress alteration around parent wells affect child fracture interactions thus impacting completion effectiveness, well productivity, and well spacing. Endeavor Energy Resources (EER) had a unique opportunity to study parent (hereafter referred to as primary) and child (hereafter referred as infill or active well) interactions and the effects of producing vertical wells on fracture behavior. Two active horizontal wells cross both developed and undeveloped acreage where half of each well is an infill between existing horizontals and the other half is in undeveloped acreage with two existing vertical wells. Operation-driven fracture fluid movement was analyzed by monitoring the treating pressure of the two active wells being completed; and the pressure response of nine shut-in offset horizontals, and ten vertical wells. The measurements and analysis establish a base case to which future fracture- interference monitoring techniques will be compared and later mitigation and intervention.
Primary horizontal wells offsetting two infill wells were monitored with wellhead pressure sensors and ESP downhole pressure sensors. Two vertical observation wells (VOW) between the new infill wells were fitted with wellhead wireless pressure sensors and bottomhole pressure gauges. During this area's original development in 2016, vertical wells located hundreds to thousands of feet from the active fraccing well experienced frac interaction. To measure the severity of the invasive fluid movement, wellhead sensors were installed on vertical wells one-half mile, one mile, and one- and-a-half miles away from the active wells. Water and oil tracers were used in the two active infill wells to study fracture fluid movement in conjunction with pressure data.
In the unexploited section, the observation horizontal wells’ pressure responses were examined for fracture shadowing (inter-well poro-elastic response) stress shadowing (intra-well dynamic active fracture interactions (DAFI) (
Legacy fields in Midland Basin are usually Held by Production (HBP). Consequently, horizontal development may be around existing vertical wells. Redevelopment of acreage into unexploited benches after primary benches have been horizontally developed is another situation many companies face. By sharing this case study, the authors want other operators who are facing these common issues to leverage these learnings. The significance of ignoring potential fracture interference and hydraulic connection may result in ineffective fractures, reduced stimulated reservoir volume (SRV), or wells sharing SRV. Ultimately this means reduced resource recovery which may occur in either or both the primary and infill wells.
A data set is presented which involves pumping multiple, unique chemical tracers into a single ‘Wolfcamp B’ fracture stage. The goal of this tracer test is to shed light on the flowback characteristics of individually tagged fluid & sand segments by adding another layer of granularity to a typical tracer flowback report. The added intra-stage level detail can provide insights into fracture behavior when stimulating shale reservoirs by looking at individual fluid segment tracer recoveries. This data set could aid in the interpretation of:
Identifying fluid segments placed outside of the P-SRV (Propped Stimulated Reservoir Volume) Fracture Complexity
Identifying fluid segments placed outside of the P-SRV (Propped Stimulated Reservoir Volume)
A total of 12 water phase tracers and 12 oil phase tracers were injected sequentially from "Pad" to "Flush". After pumping the pad stage, unique tracers were used to tag the "Proppant Laden Fluid" from the 0.2 ppa 100 mesh sand stage to the 2 ppa 40/70 mesh sand stage, before going to flush. The flush volume was not traced. Upon flowback, produced fluids were analyzed for the concentration of each tracer within the produced fluid samples. The first goal was to determine whether any traced fluid would be placed within "unpropped" SRV. The second goal was to determine the order of load fluid returns, to verify the "first-in, last-out" phenomenon, and to ascertain any degree of fluid mixing, which could be an indication of increased fracture complexity.
The results illustrate the average tracer concentration and arrival time of each traced fluid segment, which was then used to characterize the fracture stage. All tracers were detected in the produced fluid samples, indicating that no traced segment was placed outside of the propped fracture network. The results also indicate that significant tracer mixing occured within the fracture network, a potential indicator of fracture complexity. All individually traced segments flowed back simultaneously, albeit at varying tracer concentrations. The residence time calculation for each tracer showed that frac fluid injected into the later proppant segments generally flowed back faster than the earlier segments. No obvious piston-like displacement of frac fluid was observed from the tracer data.
Kåre Langaas and Emile J. W. G. Jeurissen, Aker BP ASA, and Hailu Kebede Abay, Resman A/S Summary In this paper we describe the analysis, test, and design work to deliver an optimal lower completion for a trilateral well by integrating passive and autonomous inflow-control devices (ICDs) (AICDs) at the Alvheim Field offshore Norway. In 2015, both passive ICDs and AICDs were tested in the laboratory with Alvheim fluids at reservoir conditions. The experimental flow testing demonstrated that the AICD chokes gas more efficiently than the passive ICD. The experimental results enabled correct modeling of AICDs in both the reservoir-simulation model and the simpler steady-state inflow model. The following lower-completion strategy was established for the new well: Where the well was close to the overlying gas cap, AICDs should be used, whereas passive ICDs with variable strength were to be used elsewhere to optimize the inflow. During the drilling phase, the steady-state model was updated with the as-drilled information; the lower-completion design for each branch focused on obtaining what was estimated to be an optimal inflow depending on the oil volume per drainage area. A key uncertainty in the design work was whether shaly zones along the wellbore would creep/collapse with time and act effectively as packers. The lower completion covered 7 km of reservoir penetration in the three branches, and 15 unique oil tracers were installed to evaluate the cleanup and the inflow profile along the well. In August 2016, a restart-tracer-sampling campaign was performed after a 12-day shut-in, and this formed the basis for a "chemical production log." The tracer-based inflow interpretation was compared quantitatively with the model-predicted inflow and qualitatively to the tracer responses seen during the cleanup. The comparison confirmed that the lower completion works as initially planned. The interpretation further indicated that the upper zone has a lower degree of pressure support than the lower zone, and that the larger shaly sections have creeped/collapsed and act as packers.