Tracer technology has evolved significantly over the years and is being increasingly used as one of the effective tools in the reservoir monitoring and surveillance toolbox in the oil and gas industry. Tracer surveys, conducted either as inter-well tests or single-well tests, are one of the enabling technologies that can be deployed to investigate reservoir flow performance, reservoir connectivity, residual oil saturation and reservoir properties that control displacement processes, particularly in improved oil recovery (IOR) and enhanced oil recovery (EOR) operations. As part of the comprehensive monitoring and surveillance program for an IOR injection pilot project in a Jurassic age reservoir, an inter-well chemical test (IWCTT) was designed and implemented to investigate reservoir connectivity between injector and producer well pairs, water breakthrough times ("time of flight"), and possible inter-well fluid saturations. Four unique tracers were injected into four individual injectors, respectively, and their elution were monitored in the four "paired" up-dip producers. In addition to the reservoir connectivity and breakthrough times between the injector and producer pairs, the results showed different trends for different areas of the reservoir. A detailed analyses of the exit age distribution and residence time distribution (RTD) curves showed two peaks for three of the injector-producer pairs and a single peak for the last pair. These were reflective of some apparent reservoir heterogeneities that were not anticipated at the beginning of the pilot. This paper reviews the complete design and implementation of the tracer test, field operational issues, analyses, and interpretation of the tracer results. The tracer data has been very useful in understanding well interconnectivity and dynamic fluid flow in this part of the field. This has led to better reservoir description and an improved dynamic simulation model.

Tracers are increasingly being deployed as an effective reservoir monitoring and surveillance (M&S) tool in the oil and gas industry. In particular, the single-well chemical tracer test (SWCTT) is being widely used to estimate remaining oil saturation (ROS) or residual oil saturation (Sor), especially in improved oil recovery (IOR) and enhanced oil recovery (EOR) operations. The test provides a direct measure of ROS in a wider reservoir volume compared to the measurements made by near wellbore logs or cores. A SWCTT was designed and implemented in a carbonate field to determine fluid saturations. The reservoir is heterogeneous with layers of high to low permeability limestone, porosity in the range of 20–30%, and interspersed with patchy layers of dolomites and a very competent anhydrite seal. The SWCTT was conducted in a very mature part of the field near the peripheral water injectors, to determine the residual oil saturation before a planned IOR pilot test. This paper presents the complete design and implementation of the test, operational challenges, and the analyses and interpretation of the results. The depth of investigation was 13–14 feet from the wellbore. Laboratory results of determining the partitioning coefficient of the chemical tracer are described and presented. The design of the tracer test taking into consideration the reservoir properties are shared. Considerable operational challenges in the field and appropriate solutions to overcome them provide a very interesting case study. The returns and analyses of the samples provided a unique set of data that were interpreted using a simple analytical tracer model which was comparable to the reservoir simulations predictions. The Sor was obtained after fitting the tracer return data to a model of the classical convection-dispersion equation. The results indicate that there was no displacement or drift that occurred during the shut-in period. The mass balance of the tracers suggests that more than 98% of the tracers were recovered with negligible tracer adsorption during the test duration. The results are in close agreement with a similar test benchmarked independently by a commercial vendor using a different injection design scheme.

Fiber-optic sensing technology has gradually become one of the pervasive tools in the monitoring and surveillance toolkit for reservoir and production engineers. Traditionally, sensing with fiber optic technology in the form of distributed temperature sensing (DTS) or distributed acoustic sensing (DAS), and most recently distributed strain sensing (DSS) and distributed chemical sensing (DCS), were done with the fiber being permanently clamped either behind the casing or production tubing. Clamping the fiber behind tubing or casing is sometimes beleaguered with operational challenges that often lead to rendering the fiber partially damaged or inoperable. The emergence of the composite carbon-rod (CR) system that can be easily deployed in and out of a well, similarly to wireline logging, has made it possible to sense any well without prior fiber-optic installation. In this paper, we present the lessons learned from the first well where we deployed in-well fiber-optic DAS/DTS. The DAS/DTS sensing was done in a few vertical oil producer wells and water injector wells without prior fiber-optic installation. The key objectives of the tests were to (1) investigate any well integrity across the entire length of each well, (2) assess production and injection flow profile across the perforations and behind casing, which hitherto was not possible with conventional production logging tool (PLT) tool, and (3) investigate the possibility of using the combination of distributed acoustic survey and distributed temperature survey for quantitative production flow analysis. This paper reviews the complete design and implementation of the in-well fiber-optic deployment, field operational issues, analyses, and interpretation of the sensing results. The combination of DAS/DTS data showed no well integrity related issues. The sensing data surprisingly pinpointed a few geological features such as cooling shallow aquifers that hitherto had not been noticed. The combination of different pulse widths during shut-in and production/injection cycles helped to refine the resolution of the flow profile from the production and injection zones.

Tracer technology has evolved significantly over the years and is now being increasingly used as one of the effective monitoring and surveillance (M&S) tools in the oil and gas industry. Tracer surveys, deployed as either interwell tests or single-well tests, are one of the enabling M&S technologies that can be used to investigate reservoir connectivity and flow performance, measure residual oil saturation, and determine reservoir properties that control displacement processes, particularly in improved oil recovery (IOR) or enhanced oil recovery (EOR) operations. As part of a comprehensive monitoring and surveillance program for a GAS-EOR pilot project, an interwell gas tracer test (IWGTT) was designed and implemented to provide a better understanding of gas flow-paths and gas-phase connectivity between gas injector and producer pairs, gas-phase breakthrough times ("time of flight"), and provide pertinent data for optimizing water-alternating-gas (WAG) field operations. Additional objectives include the detection and tracking of any inadvertent out-of-zone injection, and acquisition of relevant data for gas reactive transport modelling. Four unique tracers were injected into four individual injectors, respectively, and their elution were monitored in four "paired" updip producers. In addition to the reservoir connectivity and breakthrough times between the injector and producer pairs, the results showed different trends for different areas of the reservoir. The gas-phase breakthrough times are slightly different from the water tracer breakthrough times from a previous inter-well chemical tracer test (IWCTT). Residence times for the tracers indicate different trends for three of the injector-producer pairs compared to the last pair. These trends reflect and support conclusions regarding reservoir heterogeneities also seen from the previous IWCTT, which were not anticipated at the beginning of the GAS-EOR pilot. This paper reviews the design and implementation of the tracer test, field operational issues, analyses, and interpretation of the tracer results. The tracer data has been very useful in understanding well interconnectivity and dynamic fluid flow in this part of the reservoir. This has led to better reservoir description, improved dynamic simulation model, and optimized WAG sequence.

Acidizing is a common stimulation treatment in carbonate reservoirs. Acid distribution over all layers and areas around a treated well is crucial for the matrix stimulation success. Effective acidizing, especially for long horizontal wells, requires acid diverting technique to insure uniform distribution along the wellbore intervals. Mechanical diversion is costly, while chemical diversion using in-situ gelled acid and viscoelastic surfactants have widely been applied during matrix stimulation. These chemical methods showed not only limited efficiency, but can introduce damage to the treated formation. Several chemical additives and complex formulations usually are used to ensure stability and success of diverting fluid application. This exercise greatly increases the treatment cost. This study introduces a novel solution to improve acid diversion using in-situ foam generation. Thermochemical fluid is used to generate foam in-situ at downhole conditions, which will divert acid stages into not treated sections of the reservoirs. In this paper, two field treatments of two water injector wells, a vertical and a horizontal, were demonstrated using the new system. The in-situ foam generating fluid was used to divert acid in several pumping stages to ensure homogenous treatment. Pumping sequence and treatment mechanisms were described. The results showed that in-situ foam generation approach has a very effective performance in diverting acid, with superior results compared to conventional diversion using viscoelastic surfactants. As the new system generates foam downhole, it showed very practical operation procedures. No pumping difficulties are experienced, compared with surface pumping to the foam. Having the reaction activated downhole, made the whole treatment safe and friendly to apply. Foam can occupy large areas, so less fluid is required to divert acid stage. Moreover, no complex formulation was required with several additives to ensure fluid activation downhole, which significantly reduced the overall treatment cost. The novel method will enable effective and homogenous acidizing of carbonate reservoirs and eliminate the need for viscoelastic surfactants, which is expensive with limited effect. This work presents an effective method to place acid uniformly across a treated well using in-situ foam generation.