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The single well chemical tracer (SWCT) test can be used to evaluate an Improved oil recovery (IOR) process quickly and inexpensively. The one-spot procedure takes advantage of the nondestructive nature of the SWCT method. The single-well (one-spot) pilot is carried out in three steps. First, Sor for the target interval is measured (see Residual oil evaluation using single well chemical tracer test. Then an appropriate volume of the IOR fluid is injected into the test interval and pushed away from the well with water.
Using the single well chemical tracer (SWCT) test avoids the problems of too-wide well spacing and excessive tracer dispersion caused by layering that can occur with well to well tests. In the SWCT test, the tracer-bearing fluid is injected into the formation through the test well and then produced back to the surface through the same well. The time required to produce the tracers back can be controlled by controlling the injected volume on the basis of available production flow rate from the test well. In a single-well test, tracers injected into a higher-permeability layer will be pushed farther away from the well than those in a lower-permeability layer, as indicated in Figure 1a; however, the tracers in the higher-permeability layer will have a longer distance to travel when flow is reversed. As the tracer profiles in Figure 1b show, the tracers from different layers will return to the test well at the same time, assuming that the flow is reversible in the various layers.
The single-well chemical tracer (SWCT) test is an in-situ method for measuring fluid saturations in reservoirs. Most often, residual oil saturation is measured; less frequently, connate water saturation (Swc) is the objective. Either saturation is measured where one phase effectively is stationary in the pore space (i.e., is at residual saturation) and the other phase can flow to the wellbore. Recently, the SWCT method has been extended to measure oil/water fractional flow at measured fluid saturations in situations in which both oil and water phases are mobile. The SWCT test is used primarily to quantify the target oil saturation before initiating improved oil recovery (IOR) operations, to measure the effectiveness of IOR agents in a single well pilot and to assess a field for bypassed oil targets.
Terentiyev, Aleksey Alekseyevich (SamaraNIPIneft LLC) | Roschin, Pavel Valeriyevich (SamaraNIPIneft LLC) | Nikitin, Aleksandr Valeriyevich (SamaraNIPIneft LLC) | Kozhin, Vladimir Nikolaevich (SamaraNIPIneft LLC) | Pchela, Konstantin Vasiliyevich (SamaraNIPIneft LLC) | Kireyev, Ivan Ivanovich (SamaraNIPIneft LLC) | Demin, Sergei Valerevich (SamaraNIPIneft LLC) | Litvin, Aleksandr Tarasovich (SamaraNIPIneft LLC) | Struchkov, Ivan Aleksandrovich (Tyumen Petroleum Research Center LLC)
Summary: One of the complications at the stage with steam injection start into the SAGD injection well in the Terrigenous reservoir with extra-heavy oil (EHO) is its injectivity rate. Traditionally, preheating the well bottom-hole (BH) zone with steam and subsequent recovery of hot water or steam through the annulus is used to get adequate injectivity. As an alternative to steam preheating it is proposed to inject an aromatic solvent/reagent to ensure sufficient well injectivity. Calculations were performed with the real reservoir model. The mutual influence of wells in SAGD blocks under the conditions of solvent/reagent injection was studied for this.
Kumar, Anjani (Computer Modelling Group Ltd.) | Warren, Gregory (Computer Modelling Group Ltd.) | Joslin, Kevin (Computer Modelling Group Ltd.) | Abraham, Anson (Computer Modelling Group Ltd.) | Close, Jason (Computer Modelling Group Ltd.)
Abstract Computing hardware and reservoir simulation technologies continue to evolve in order to meet the ever-increasing requirement for improving computational performance and efficiency in the oil and gas industry. These improvements have enabled the simulation of larger and more complex reservoir models. When working with steam assisted gravity drainage (SAGD) operations, determining the optimal steam injection rates and allocation of steam among various multi-well pads is very important, especially given the high cost of steam generation and the current low oil price environment. As SAGD operations mature, steam chambers start to coalesce and interact with each other, forcing producers to face declining oil rates and increasing steam oil ratios (SOR). Operators must work to reduce injection rates on declining wells to maintain a low SOR and free up capacity for newer, more productive wells. Steam injection and allocation between wells and multiple pads then becomes an exercise of optimizing cost, and improving productivity and net present value (NPV). A case study is performed on a full field SAGD model by optimizing steam delivery aided by Artificial Intelligence (AI) and machine learning enabled algorithms for automated numerical tuning, and dynamic gridding technologies. The model contains 15 pads, 96 well pairs (192 wells), 12.6 million active simulation grid blocks, and represents a typical Athabasca formation geology and fluid properties. The proposed steam delivery optimization considers two main scenarios. The first scenario considers the case in which steam generation capacity is limited, and the optimization process intelligently determines the optimal well and pad level steam injection rates dynamically during the life of the project. The second scenario assumes that steam generation availability is not constrained and the field development plan is optimized based on steam required for maximum recovery from the field as fast as possible. A full field optimized development plan is created for the 15 SAGD pads and 96 well pairs. Following the optimization, an increase in NPV and reduction in SOR is achieved for the entire field due to the efficient utilization of total available steam. The optimization study required several full field SAGD simulations to be completed in a practical time period, demonstrating that workflows such as this can be carried out for full field thermal models. These models can also be used to evaluate production responses due to varying operating strategies in the field. This paper presents the optimization of steam allocation for a full field, multi pad SAGD simulation model. It demonstrates that advances in computing and reservoir simulation technology have enabled the simulation of full field models within a reasonable timeframe, allowing engineers to tackle a new class of problems that were previously impractical.
Even with a properly designed single well chemical tracer (SWCT) test, interpreting the data requires judgment calls, and typically, simulation, to arrive at a final estimation of residual oil. Tomich et al. report one of the earliest SWCT tests, which was performed on a Frio Sandstone reservoir on the Texas Gulf Coast. The results of this test are used here to demonstrate the details of SWCT test interpretation for an ideal situation. The test well in the Tomich et al. report was in a fault block that had been depleted for several years. Because of the natural water drive and high permeability of the sand, the formation was believed to be near true Sor.
The single-well chemical tracer (SWCT) test is an in-situ method for measuring fluid saturations in reservoirs. Most often, residual oil saturation (Sor) is measured; less frequently, connate water saturation (Swc) is the objective. Either saturation is measured where one phase effectively is stationary in the pore space (i.e., is at residual saturation) and the other phase can flow to the wellbore. Recently, the SWCT method has been extended to measure oil/water fractional flow at measured fluid saturations in situations in which both oil and water phases are mobile. The SWCT test is used primarily to quantify the target oil saturation before initiating improved oil recovery (IOR) operations, to measure the effectiveness of IOR agents in a single well pilot and to assess a field for bypassed oil targets. Secondarily, it is used to measure Swc accurately for better evaluation of original oil in place (OOIP). Fractional flow measurement provides realistic input for simulator models used to calculate expected waterflood performance. This chapter familiarizes the reader with the SWCT method, and offers guidelines for selecting suitable test wells and for planning and executing the field operations on the target well. Test interpretation is also discussed and illustrated with typical examples. The first SWCT test for Sor was run in the East Texas Field in 1968. Patent rights were issued in 1971. Since then, numerous oil companies have used the SWCT method.
Simple analytical interpretation of single well chemical tracer (SWCT) is possible if one assumes uniform oil saturation, negligible hydrolysis during injection and production and assuming similar dispersion for all reservoir layers. In complex reservoir settings, including multilayer test zones, drift, cross-flow etc., reservoir simulation tools, capable of handling the hydrolysis reaction are commonly applied (Jerauld et al., 2010; Skrettingland et al., 2011). In practice, coupled flow and chemical reaction simulators (see e.g. CMG, 2010; and UTCHEM, 2000) are used. Such coupled simulations are CPU-demanding enough that execution time may be an issue, especially when small grid-size are applied to avoid numerical smearing.
The single-well chemical tracer (SWCT) test is an in-situ method for measuring fluid saturations in reservoirs. The most common use is the assessment of residual oil saturation (Sor) prior to improved oil recovery (IOR) operations (post-waterflooding). The SWCT test for Sor uses only one well and involves the injection and back production of water carrying chemical tracers. A typical target interval for SWCT testing is shown in Figure 1. The candidate well should be completed only to the watered-out zone of interest (zone at Sor).
Al-Mai, Noura (Kuwait Oil Company) | Al-Shuaib, Muna (Kuwait Oil Company) | Alvarado, Omar (Kuwait Oil Company) | Al-Nesef, Mohammad (Kuwait Oil Company) | Al-Saleh, Alaa (Kuwait Oil Company) | Al-Qahtani, Shaikha (Kuwait Oil Company) | Useche, Marcos (Schlumberger) | Franco, Francy (Schlumberger) | Orjuela, Jaime (Schlumberger) | Wibowo, Arif (Schlumberger) | Prakash, Roshan (Schlumberger) | Gornescu, Bogdan (Schlumberger)
Abstract An improved workflow for handling an excess of Hydrogen Sulfide (H2S) in treatment facilities is presented. The objective is for the selection of wells to decrease H2S production by reduction of choke sizes with the lowest possible impact on oil production. During operational restrictions in a gas treatment plant, it is necessary to reduce the H2S quantity received at the facility. To perform this operation, an approach is to limit the production from wells with the biggest rate production of H2S (volume); another solution is to restrict the wells with the highest concentration of H2S (% molar - composition); However, both scenarios have an impact on oil production. KOC - KwIDF Jurassic, has developed a procedure that considers the derivative of the produced H2S curve as a function of produced Oil to find the optimal scenario. The proposed method was evaluated using the results from a sequence of monthly allocations that include characteristics such as: facility, number of wells, and fluid compositions. The data was analyzed applying three methodologies that have different objective functions, such as H2S volume, H2S concentration, and a new criterion called H2SOR. As a result, there were three different way to rank the wells to reduce H2S production. A monthly plot of Cumulative H2S Production vs Cumulative Oil Production was prepared to calculate the derivative of the curve, finding the optimal solution at different levels of H2S treatment restriction. Finally, the economic analysis for each method was also calculated. H2SOR methodology guarantees the best alternative to ensure the restriction of sour gas rates with the lowest impact on oil production. It also proves to be the best solution from the economical point of view.