This paper presents a method of using chemical tracer data to quantitatively evaluate interwell communication in various well configurations by combining raw tracer data with field production data. Qualitatively, tracer breakthrough in an offset well indicates that there is communication between the infill and primary well, but by utilizing the method described in this paper, the fracture driven interaction (FDI) severity can be quantified by determining the total mass of tracer produced out of the primary well and new wells. The technique yields an allocation of load fluid and hydrocarbon recovery at each well and associated formation.

Completion diagnostics have been extensively utilized in hydraulically fractured horizontal wells across all major basins to determine the effectiveness of stimulation strategies and to evaluate new technologies. They have also been key in understanding factors that drive well performance and reduce completion costs. Geological heterogeneity provides unique challenges and opportunities for completion optimization. Diagnostic data provide insights into fracture characterization under various geological conditions and how they can be utilized for well design and field development. This paper demonstrates the integration of geology with completion diagnostics results. The dynamic relationship between evolving completion technologies and geology is brought to light with the help of case studies across multiple basins. The challenges studied include fracture driven interactions (frac-hits), perforation cluster design, landing zone optimization and production analysis. By incorporating geology into the diagnostic results, additional insights are obtained for enhanced reservoir characterization and future field development. The case histories illustrate how the interpretation of diagnostic data can be strengthened by a combined understanding of geology and completion technologies, instead of employing an independent approach. In one instance, a high degree of fracture driven interactions (frac-hits) from new completions to existing producers was observed. Further detailed study of geological features in the section revealed that the frac-hits were primarily due to the presence of the faults rather than by well proximity and stimulation treatment volumes. In another example, diagnostics data identify low hydrocarbon productivity across several stages within a well. The load fluid recoveries in these stages with low hydrocarbon flowback are comparable to better performing stages, indicating effective stimulation and flow capacity within the fracture. This underscores the importance of comprehensive lithology evaluation across the lateral to identify low productivity intervals, for improving future well placement and performance. The outcomes of these case studies provide examples of the barriers between engineering and geology being broken through data corroboration. Asset level decisions surrounding the integration of multiple technical teams offer an opportunity to reduce the learning curve in basin development strategies. This study releases case studies across multiple basins that leverage this integration. The approach outlined in this paper can be applied in any horizontal field development program.

This case study reviews the new development program of Occidental's Yoakum County, Texas asset in the Permian Basin. The focus is on well planning and completion design, with the objective of improving sweep efficiency and mitigating water breakthrough in newly drilled and completed wells. This effort is supported primarily through the initial completion design utilizing re-closable sleeves along with the collection and interpretation of data, which allowed Occidental to make impactful adjustments with reasonably low risk and capital expenditure. Occidental's success in this unit is largely due to the initial planning and tailored completion design that supported initial stimulation, and future waterflood results. Seeking to improve production in a waterflood field that had been producing for several decades, Occidental identified reservoir sections that appeared not to be swept effectively by the ongoing, originally designed, waterflood program. Focusing on a high-oil-potential target area, that had not been fully exploited, Occidental devised a program to improve sweep efficiency by converting two vertical producing wells to injectors, returning a temporarily abandoned vertical injector well to service, and drilling one new vertical injector well. Also planned were two new horizontal producer wells with the intent to include re-closable sleeves in both. The two new producer wells faced two challenges: 1. A water-bearing strata below the target zone which presented a risk of impaired oil production should induced fractures connect to the water zone; 2. Based on production history and known reservoir complexities in the target area, there was a high probability of future water breakthrough problems. This work brings lessons to the forefront that could add significant value when planning and executing new wells in existing waterfloods, including: Integration of geoscience and diagnostic methods to better understand the major influences on well performance, in particular, accurately identifying water breakthrough Optimizing completion design to eliminate water breakthrough and increase the profitability of a legacy waterflood field development plan.

The STACK (Sooner Trend Anadarko Canadian and Kingfisher counties) is a prolific multi-target stacked play in Oklahoma. Development challenges in the STACK are underpinned by fieldwide geological heterogeneities, including variable reservoir quality throughout the Sycamore-Meramec and Woodford formations and the presence of natural fractures and dense laminations. This case study examines the operator's first fully co-developed section in Canadian County, which comprised of 11 wells across 4 targets. This project was undertaken after de-risking much of the geological uncertainty in several offset pads. The data acquisition program was designed to assess the impact of total completion design including: interwell spacing, targeting, and wine-rack configuration on well-to-well connectivity and well performance in full section development. Within the section, half of the wells were drilled with the same spacing as offset pads and the other half were downspaced. On both sides of the section, similar targets received the same hydraulic fracturing design. Given it was the operator's first full section development in the county, the operator utilized an advanced data acquisition program that included downhole pressure gauges, chemical tracers, and DNA based diagnostics. DNA diagnostics proved especially useful in measuring the relative contribution from the multiple strata between landing zones, which would not have otherwise been possible. Although the previous offset pilot pads were developed with similar spacing and completion parameters, there were significant differences between average production profiles, with higher initial production (IP-180) observed in the full section. This paper evaluates these production differences by examining the impact of well spacing/targeting, completion design, and interwell communication on well performance in full section development. Well performance was assessed by integrating production, pressure, and tracer data, along with DNA based diagnostics. DNA diagnostics played a key role in assessing and monitoring the duration of interwell communication between offset wells across the section. Results from this integrated approach demonstrated that full section well performance was impacted by completion design and interwell communication in three notable ways: 1) interbench co-development significantly increased communication across perceived deterrents to fracture growth, 2) well-to-well communication was influenced by completion order, and 3) aggregate interwell communication was higher in full section development than in pilot pads, which may have contributed to the full section initially outperforming pre-drill expectations. The differences in well performance and well-to-well connectivity carry important implications for operators who plan to use partial spacing tests to develop multi-target full sections. Specifically, these observations underscore the potential for similar completion designs to yield materially different well performances between full section and 1 to 3 well pad development. These results also demonstrate the ability of DNA based diagnostics to accelerate learnings in full section development, which may have otherwise required additional CAPEX to test via heuristic techniques.

The scope of this project involves finding a passive dye tracer that will improve the efficiency of tracer analysis for lab and field applications. The idea is to develop an "expert system" to obtain tracer concentration based on the colour change of outlet samples, i.e. a computer-based visual analysis method, aimed at circumventing complicated analysis methods which require spectrometers or chromatographs. This method shall correlate the mixture colour to component concentration. Primary considerations for selecting a proper component are: dye and its analysis procedure should be cost-effective, dye component should be benign, it should not interact with the rock and fluid, and it should be environmentally friendly. With this method, lab and field tracer applications can be simplified, and tracer concentration curves can be obtained immediately after collecting the samples.

Interwell tracers have been shown to provide invaluable information about reservoir dynamics, well connectivity, and fluid flow allocations. However, tracer tests are often applied sporadically because their immediate returns of investments are not readily apparent to a resource-holder. Here, we rigorously demonstrate that tracer data can indeed improve reservoir history matching, and, more importantly, improve future production, using reservoir simulations on benchmark problems. Sensitivity studies and the limitations of tracer data are also provided. The numerical experiments were divided in two sections. First, production data with or without tracer data from reference fields were collected for the first water flooding periods for history matching. Second, the history matched models from the first section were used for production optimization for the next water flooding periods. The ensemble smoother with multiple data assimilation (ES-MDA) was used for the history matching processes for the first part of the numerical experiments, and the modified robust ensemble-based optimization (EnOpt) was adopted to maximize the net present value (NPV) for the second part of the numerical experiments. The three-dimensional channelized "Egg Model" was chosen as the initial benchmark problem. From the first part of the numerical experiments, using the same hyper-parameters, it was observed that history matching including tracer data resulted in a better match of the field production rates with smaller standard deviations. In addition, history matching including tracer data resulted in more distinct geological features when observing the history matched permeability maps. From the second part of the numerical experiments, we observed that the geological models history matched including tracer data resulted in better production optimization with higher NPV produced. In the specific case of the Egg Model, +4.3% increase of the NPV was observed. To understand the sensitivity and the limitations of the tracer data, the same numerical experiments were performed on a library of reservoir models with different fracture patterns. After the history matching and production optimization simulations, we observed that including tracer data gave positive NPV increases ranging from +0.3% to +9.4% from 5 of the 7 test cases. It was observed that tracers were more effective for the non-homogeneously flooded reservoirs. To the best of our knowledge, this paper is the first study that quantifies the benefits of tracers in the context of the improved production, measured in NPV. In a broader perspective, we believe this is the best way to test any new history matching algorithms or reservoir surveillance methods. In this work, we show that tracers can result in positive NPV in most situations, and oil producers using large-scale water flooding operations would benefit from performing more tracer tests in their operations.

The main challenge facing any nanoparticle-based reservoir agent stability and transport through hydrocarbon reservoirs under harsh conditions (typically up to 220 kPPM TDS, ~10% divalent cations, 100°C temperature and 3200 psi pressure) without loss or degradation. Therefore, appropriate understanding of the physical and chemical character of candidate systems, e.g. ADOTS fluorescent nano-tracers, is highly needed. Results reported here show that the pre-injected ADOTS diluted in DI water, HPLC water and seawater have exactly the same 450 nm peak under the fluorescence spectrophotometry. However, both pre-injected and filtered post-injected ADOTS samples have also exactly the same peak position. Raman measurements are identical confirming the presence of ADOTS in samples before and after the injection. This improved physical and chemical understanding supports future development of both coatings and novel cores on the ADots platform.

Luminescent upconversion nanoparticles are used as alternate fluorescence tracers to overcome the interference of organic molecules in the analysis of flowback waters. Upconversion nanoparticles use low-energy excitation at approximately 980 nm with high-energy emissions in the region of 200 to 950 nm. Emission properties of the nanoparticles are tuned by selective doping, and their dispersiblity in water and oil are altered through appropriate functionalization. The flow experiments used stable crude oil emulsions in API brine with the mixture of two different emission upconversion tracer nanoparticles. Data from these experiments suggest that the nanoparticle tracers can flow through the porous media and distinguish between each other, even in the presence of organics in an emulsion. This capability can open new avenues in in-situ reservoir communication and understanding.

Kuwait Oil Company is pursuing fast track technology deployment in its fields to meet the strategic target of production. The horizontal wells provide good mean to exploit the reservoir through increased reservoir contact but it brings some inherent problems in optimizing production and low cost well intervention. To address these inherent challenges, the deployment of inflow control device (ICD) has become a normal trend of completion in horizontal wells. The completion of horizontal wells with ICDs helps in optimizing production but information of inflow contribution from each section qualitatively and quantitatively is still a challenge. In this perspective, KOC has deployed intelligent chemical inflow tracer technology combined with On/Off ICDs below an ESP in a horizontal well located in its northern field to assess the inflow performance of the production. The horizontal well was drilled through a heterogeneous reservoir, which was compartmentalized with swell packers and completed with On/Off ICDs. In these types of wells, traditional production logs are considered risky and expensive due to the limitations of using a small-diameter coil tubing, which must fit through the Y-tool on the ESP. This small diameter coil tubing will go into helical buckling before reaching the toe of the well resulting in an incomplete log for the well. In some cases, the wells are lacking Y-Tool facility, which practically does not allow production logging in the well. In such cases, the intelligent chemical inflow tracers are used to provide a qualitative assessment of the clean-up phase of production, quantitative inflow information from each zone, and to identify the section producing water along the horizontal well. The use of intelligent tracers overcame the intervention challenges by installing intelligent downhole chemical sensors in pup-joint carriers next to the ICD joints in each compartment from heel to toe to meet monitoring objectives of Kuwait Oil Company. Fluid samples collected from the surface flow lines were analyzed for unique chemical tracer signatures and interpreted the corresponding tracer signals. This has resulted into identification of quality of fluid flowing from each section concomitant with its quantification. In addition, the pilot results have increased the reservoir understanding that leads to optimum ICD designs for future wells in the same reservoir. This paper discusses the first well installation of its kind in Kuwait, the methodology for selecting the technology, the deployment in the well, and the interpretation of results of water and oil tracers obtained during different monitoring campaigns through fluid sampling.

Tracers play an important role in the oil and gas industry by providing valuable information about reservoirs. In particular, tracers can help in mapping water movementfor determining information on water flooding that can be used to improve hydrocarbon recovery efforts. Some of the challenges associated with current chemical or dye-based tracer technology are thermal degradation over time, phase separation, and tedious detection processes. To overcome these drawbacks environmentally friendly, multicolor silica nanoparticles as tracershavebeen proposed toprovide simpler and faster detection through fluorescence spectroscopy.

The optimistic outlook of the petroleum industry, especially with regard to natural gas, has led to a renewed interest in shale gas plays and more specifically to the Haynesville Shale formation. Through the use of post-stimulation completion diagnostics, insights have been obtained that can be utilized to optimize future hydraulic fracturing completions. This paper will illustrate the use of post-stimulation completion diagnostics in identifying trends that are associated with effective completions in the Haynesville Shale. Case histories will be presented which illustrate methods that have increased the overall completion effectiveness in relation to proppant placement, wellbore deliverability, and ultimately increased production performance. A horizontal well database (> 500 wells) was compiled to identify effective completion trends across the Haynesville Shale formation. By employing proppant and fluid-based tracers, hydraulic fracture characteristics, well deliverability, and ultimately production performance were measured to highlight trends that increased overall completion effectiveness. Primary completion results highlighted areas including, but not limited to, effective proppant placement, full lateral production, frac stage length and containment, perforation cluster spacing, wellbore lateral length, and constrained flowback effects. This paper reviews many of the insights that have been developed through this use of post-stimulation completion diagnostics in the Haynesville Shale formation and which have led to increased completion optimization, production enhancements, and field-wide cost reductions.

This paper describes the analysis, test and design work to deliver an optimum lower completion for a tri-lateral well, by integrating autonomous and passive inflow control devices (ICD), in the Alvheim field offshore Norway. Chemical tracers, permanently installed in the completion, enabled the evaluation of inflow performance in each lateral. This continues to give valuable information to assess whether the tri-lateral completion is performing as predicted, improves reservoir characterisation and guides reservoir management decisions. In 2015, both passive and autonomous inflow control devices (AICD) were tested in the laboratory with Alvheim fluids at reservoir conditions. The experimental flow testing, reported in this paper, demonstrated that the AICD chokes gas more efficiently than the passive ICD, but also that the strength of the AICD were lower than expected a priori. The experimental results were used to model the AICD correctly and establish a lower completion strategy as follows: where the well was close to the overlying gas cap, AICDs should be used, while passive ICDs with variable strength were to be used elsewhere to optimise the inflow. Steady-state inflow modelling was performed before the drilling operation and updated accordingly with the as drilled information. The lower completion design for each branch focused to get what was estimated to be an optimal inflow based on oil volume in place. A key uncertainty in the design work was whether shaly zones along the wellbore would creep/collapse with time and act effectively as packers or not. The lower completion covered around 7 km of reservoir penetration in the three branches, and 15 unique oil tracers were installed to evaluate the clean-up and the inflow profile along the well. The well started producing in May 2016 and downhole flow control valves enabled a successful clean-up, as confirmed by oil tracer responses. In addition, a restart tracer sampling campaign was done after a 12-day shut-in, in August 2016, and this formed the basis for a "chemical production log". The tracer based inflow interpretation is compared quantitatively with the model predicted inflow and qualitatively to the tracer responses seen during the clean-up. This gives valuable feedback to the completion design, and assist in understanding the various degrees of pressure support and if the shaly reservoir sections have creeped/collapsed or not. The well has exceeded pre-drill production expectations, with an average oil rate of 3375 Sm3/d (21240 stb/d) during the first production year. This is a consequence of higher than expected NTG, but is also partly a result of the lower completion design, where the focus has been to optimize the lower completion such that the whole well contributes, from the heel to all toes. To the knowledge of the authors, this is the first well in the world with a lower completion integrated with AICDs, ICDs and chemical tracers.

This paper presents a systematic approach to evaluate limited crossflow between layers of a stratified reservoir using interwell chemical tracer test. Previous studies either entail no crossflow between layers or assumes an established vertical equilibrium across transverse direction (owing to viscous/capillary/gravity driving mechanisms); however, they fail to detect the presence of limited crossflow between layers through a ‘bridge’; ‘bridge’ in this study is defined as apathwaythrough which crossflow takes place with an adjacent layer. Obviously, crossflow may take place through several bridges along a layer. A new formulation is developed to study and detect the limited crossflow. The crossflow is detected through monitoring of the fraction of total injected fluid that arrives at the producer from each layer as a function of time. We employed both numerical simulation and field examples to verify the proposed method. A transition period is identified during which thefraction of injected fluid flowing through each layer significantly changes because of crossflow. Our results indicate that tracer can be used to evaluate number of bridges. The distance between injector and the bridge location can significantly change the interwell tracer results. Identification of crossflow between layers and evaluation of transition zone significantly improves the current efforts to understand reservoir complexity and sweep efficiency. The outcome of this research can help design more successful EOR processes.

Understanding the actual inflow distribution across the reservoir interval is valuable for optimizing reservoir management decisions. It is common to have varying levels of uncertainty in the petrophysical prediction of the inflow distribution. The inflow distribution assessment drives many aspects of the field development plan. A technique is presented for acquiring quantitative measurements of the inflow rate of various reservoirs or layers of a reservoir at various times in the life of the well using interventionless technology. Chemical tracers are embedded in sand screens that are positioned adjacent to reservoir layers at different depths of a well such that fluid exposure causes release of a unique chemical compounds into the oil produced from each layer. Analysis of the transient behavior of each of the chemical compounds from samples of the produced oil provides a quantitative assessment of the rate of inflow occurring from the adjacent reservoir section. The chemical tracer based measurements of inflow are compared to the petrophysical predictions of inflow distribution. The petrophysical rock and fluid properties are determined using tools such as LWD and core analysis. It is common for these sources to contain uncertainty in their assessments of the inflow potential. The chemical tracer technique provides an assessment of the actual inflow distribution that can be compared to the petrophysical prediction. This additional input is very valuable in reducing the uncertainty in the overall reservoir performance assessment. Case histories from two wells in frac-packed wells are presented. Both wells had substantial uncertainties in the petrophysical assessments of the inflow performance of layers in the reservoir. The results from the chemical tracer technique provided insight that led to high value decisions. In Case History #1, the chemical tracer showed a layer to be contributing non-commercial rates. The petrophysical based prediction of inflow indicated this zone was of lower quality than the other zones but it was decided to complete the zone as there was possibility of producing economic rates. Significant savings will be realized in future wells by not completing the non-commercial layer. In Case History #2, the overall productivity of the well was substantially below predictions of the petrophysical data. The chemical tracer inflow profile showed all zones producing similarly. The assessment of similar inflow in each layer implied the kh prediction from LWD to be overly optimistic. This insight changed the production profile forecast for future wells. This insight also prevented the need to perform an expensive PLT log in the well to determine if the entire interval was flowing. Measuring the actual inflow distribution across the reservoir interval in deep, frac packed wells is usually so impractical or prohibitively expensive that it is never performed. The technique presented of using chemical tracers embedded in the completion components provides an on-demand, low cost and minimal risk means of assessing the actual inflow distribution. The inflow distribution information is combined with other data sources to reduce the uncertainty of reservoir management decisions.

Several tools and techniques exist to understand distributions of reservoir properties. Interwell tracer testing is one ofthe 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) bottom hole 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 able to give a good fit in most of the cases. Comparing among the tracer models, the combined model can better represent a tracer flow 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 non-uniqueness of the fits, leading to an improvement of tracer matching. The reservoir properties obtained in this study (Koval factor and dispersion coefficient) were also analyzed and compared to those from previous measurements.

Tracer studies are used to characterize the porous media for pore volume occupied by different phases and flow trajectories and velocity of the phases. When a tracer is injected as a pulse into a liquid stream flowing in a porous media, the stagnant or the dead-end pore volume in the porous media interacts with the tracer leading to a tailing effect in the outlet tracer curve. The tailing-effect impacts the determination of the flow path or the phase saturations in the porous media using the outlet tracer concentration. Generally, history matching of the effluent concentration profile is used to determine and separate the effect of dead-end pore volume from other tracer behavior in the reservoir such as dispersion or convection. History matching is computationally expensive and many simulation runs are required to match the exit concenetration profile. In the present work we have used the method of moments of the Residence Time Distribution (RTD) of the tracer to determine dead-end pore volume and parameters associated with it. We are able to describe from the method deviced, which parameters can be determined and which cannot be determined in different flow scenarios in the porous media. We also use numerical experiments of the tracer transport in porous media and compare the results with the method of moments. In the end, we delineate general guidelines for estimation of the parameters, especially the dead-end pore volume.

The residual oil saturation obtained from SWCTT is critical for designing enhanced oil recovery (EOR). However, a key assumption in conventional SWCTT is that only single phase (water) is mobile. In reality, this is often not the case, and significant error can occur if the conventional SWCTT analysis method is used when multiple phases flow at the same time. The objective of this study is to improve the accuracy and precision of SWCTT interpretation in multi-phase flow condition. In this paper, we propose an innovative procedure of modified SWCTT and the method of moment (MoM), aiming at the two-mobile-phase condition. In the development of the algorithm, a ratio parameter is introduced to adjust the calculated swept volume difference between the conservative tracer and partitioning tracer. In addition, a mixture injection of oil and water is required, instead of pure water injection in SWCTT. The proposed approach is verified through numerical simulation on synthetic cases with known input parameters. The simulated models consist of a radial flow regime with a single vertical well in the center. The input oil saturation varies from 0.1 (immobile oil saturation) to 0.9. Our results show that the saturation estimated from modified MoM matched the simulation input data, which indicates that our approach is able to capture the saturations under two-mobile-phase condition. Moreover, the modified MoM can also be applied in single-mobile-phase condition and improved accuracy of conventional MoM.

This manuscript reports the industry's first proven reservoir nanoagents' design and describes a successful multi-well field trial using these inexpensive and environmentally friendly nanoparticles that offer an important advantage of fast and cheap fluorometric detection. Our fundamental nanoparticle tracer template, A-Dots or Arab-D dots, is intentionally geared towards the harsh but prolific Arab-D carbonate reservoir environment of 100°C temperature, 150,000 ppm salinity, and an abundant presence of divalent ions in the connate water. The A-Dots were manufactured on a scale of one metric ton from affordable and easily available commodity chemicals. They were injected into a watered-out part of the field and monitored at four nearby producer wells for two years. Monitoring of four neighbouring producer wells over a period of 26 months confirmed nanoparticles' breakthrough at a single producer nearly 500 m from the injector at the reservoir level, thus, proving the nanoparticles' mobility and transport capability. The maximum concentration of the nanoagent in produced water was observed about 10 months after the injection matching the behavior of conventional small-molecule tracers used in the same pair of wells previously. The rate of A-Dots production correlated with the rate of water injection at the original injector well and followed it closely with a 10-month delay. This test bolstered our previous observations of satisfactory recovery of A-Dots in a single-well test by confirming their reservoir stability on industry relevant time scales and demonstrating the feasibility of their industrial production. The importance of this accomplishment is not in how sophisticated the sensing functionality of the tracer design is but rather in the nanoparticle stability, mobility, scalability, and field application potentials. Our findings render the concept of having active, reactive, and even communicative, in-situ reservoir nanoagents for underground sensing and intervention a well anticipated near-future reality.

Carbonate reservoirs are notoriously complex and difficult to characterize, due to their inherit homogeneity. The ability to understand and model such homogeneity accurately, leads to better reservoir management and improved field development strategy in terms of well placement and optimized well patterns. Dynamic reservoir model was built from the static geological model i.e. using MDT, pressure volume temperature (PVT), routine core analysis (RCA) and special core analysis (SCAL) etc. As part of the reservoir model validation process, history matching of the model was conducted to match the observed data. After history matching was completed, tracers injection analysis and streamlines modelling was conducted in other validate the reservoir model, the well patterns and improved the full field development strategy. The full field development scheme includes water alternating gas (WAG) miscible hydrocarbon gas injection, with 5 observers covering both the flank and crestal locations. The tracer analysis included the injection of 11 different tracers in 11 different injectors, and the monthly monitoring of the producers within the well pattern. Streamline model was built simultaneously from the convention compositional model, in order to analysis and predict the different tracers break through times i.e. both observed from the field and simulated. In addition to this, streamline time of flight (TOF) analysis, the effect of tracking of different tracer components, geological and geophysical impact was evaluated, in order to improve the breakthrough time match between observed and simulated time. As a result of this analysis reservoir management improved, as the source of increasing higher GOR in specific wells were discovered. Remedial actions were recommended to help reduced the increasing high GOR in the respective wells. Also the field development strategy improved, as injector's contribution per well pattern well was quantified. As a result injection could be redistributed. In producer wells with little or no support from their respective injectors, a plan was made to ensure that such patterns could be close appropriately. This improved and maintains the voidage replacement ratio (VRR) in the field, according to reservoir guidelines. This paper describes how by using gas tracer injection and streamline modelling reservoir management and field development can be improved. In addition to the improvements in reservoir management and field development strategy, several lessons learnt and best practice were suggested from the tracer and streamline study conducted. They include but are not limited to; Different tracers can show different concentration level at breakthrough wells. Wells further away from injectors can show earlier breakthrough than well close to injectors, as it is dependent on reservoir connectivity. In analyzing model breakthrough times, the measurable tracer in the field needs to be used, as opposed to the actually first breakthrough seen in the simulator. As below such concentration cannot be measured. Operational changes in wells need to be captured properly in the simulator, in order ensure improve prediction of tracer breakthrough times.

Tracer technology is a very efficient diagnostic tool for the oil and gas industry to obtain valuable information about reservoirs. The interpretation of tracers that have traversed the reservoir reveals reservoir characteristics such as inter-well connections, heterogeneities, and water movements that can be used to improve hydrocarbon recovery efforts. Commonly used tracers are radioactive elements and stable isotopes, chemicals, such as fluorescent dyes, and inorganic ions. Novel carbon quantum dots (CQDs)-based fluorescent tracers have been proposed for production and well monitoring. One-step electrochemical synthesis of CQDs from low molecular weight chemical precursors through electrochemical carbonization was developed. The doping of CQDs with heteroatoms such as nitrogen provides differentiated fluorescence emission signatures that can be used to monitor multiple stages of frac operations.