Reservoir Rock and Fluid Characterization Using Distributed Temperature Sensing DTS Systems Data

Arps in 1944 developed decline curve equations for analyzing reservoir/well production decline and the estimated decline rate constant is used for production forecast. In making reservoir production forecast, the Arps equations are usually calibrated to match the reservoir historical production decline by adjusting the decline rate constant value. The decline rate constant indirectly influences the reservoir properties responsible for production decline. However, the value assigned to the decline rate constant might either overestimate or underestimate the uncertainties in the reservoir rock and fluid properties responsible for reservoir production decline. The decline rate constant in the Arps equation has no equation relating it to the reservoir properties that are responsible for the reservoir production decline hence; the direction of uncertainty quantification on these reservoir parameters is not explicit, therefore undermining the predictive power of the Arps equations. The impact of reservoir properties uncertainties on the production rate decline and forecast by Arps equations cannot be examined due to the empirical nature of the Arps equations. Also, the decline rate constant is not explicitly related to reservoir rock and fluid properties responsible for production decline. However, the predictive power of the Arps model can be greatly improved if the decline constant can be expressed as a function of the reservoir rock and fluid properties responsible for production decline. Hence, the impact of uncertainty on the production forecast by Arps models can be examined. The objective of this work is to introduce reservoir rock and fluid properties into the Arps decline curve equations. This will enable the imposition of reservoir physics on the decline curve equations and the impact of uncertainties in these properties on matching historical production decline and forecast. In addition, a relationship between the decline rate constant in the Arps equations and the reservoir rock and fluid properties that influence reservoir production decline has been developed. A mechanistic approach using dimensional analysis was used to develop the relationship. The decline rate was assumed to be proportional to the various reservoir rock and fluid parameters, such as permeability, porosity, net-to-gross, drainage area, fluid density, and viscosity, that could influence production decline and by unit dimensional analysis, a relationship was developed between the decline constant and these reservoir rock and fluid properties. The decline rate constant was directly related to the product of reservoir permeability, fluid density, and the square of the pressure difference but inversely proportional to the cubic power of fluid viscosity. The relationship developed for the decline constant in this work will give the modified Arps model strong predictive power and allows for the impact of uncertainties on the production forecast to be evaluated. The results obtained from the modified Arps equations give better reservoir properties dependent outcomes than the traditional Arps equations and enable analysis of the effects of reservoir rock and fluid properties uncertainties on the production decline and forecast.

Operators including Aera Energy LLC are evaluating distributed temperature sensing (DTS) systems as an alternative to production logging tools (PLT) and radioactive tracer surveys (RTS) for the determination of zonal allocation factors. If DTS data can be interpreted to provide wellbore velocities, zonal allocation can be determined without well entry and practically in real-time. In comparison to PLT and RTS, DTS could provide zonal allocation at a higher measurement frequency, lower cost, and lower risk to personnel, environment, and the well asset. In wells where casing deformation precludes wireline operations, DTS may be the only viable alternative. The purpose of this work is to investigate whether water injection zonal allocation can be derived from DTS data acquired in thermal tracer injection tests within an uncertainty comparable to RTS. Three waterflood injection wells with RTS and DTS data in Aera Energy"s Belridge field in California are analyzed. The zonal allocation factors derived from the DTS are shown to agree within uncertainty with the RTS-based results. The DTS for two of the wells is interpreted through history matching with an OLGA thermal-fluid model. The DTS for a third well is interpreted using the Temperature Inflection Point (TIP) thermal tracer method proposed in this work. The TIP method is a simpler alternative to history matching and was shown to be theoretically valid for wells with negligible heat transfer at the walls over the duration of the injection test. In this regard the TIP method is less restrictive than the Slopes method, which is currently used in industry but theoretically requires negligible heat transfer at the walls and within the fluid. The TIP method is also shown to be more consistent with the field data of this study. The paper concludes with guidelines on the design and implementation of thermal injection tests and TIP analysis. The most significant practical limitation of the TIP method is its sensitivity to noise in the data, motivating DTS acquisition at the maximum practical resolution, data smoothing, and averaging over multiple test realizations.

Temperature monitoring using Distributed Temperature Sensing (DTS) technology

Reservoir Rock and Fluid Characterization Using Distributed Temperature Sensing (DTS) Systems Data

While drilling through a reservoir, a lot of valuable information can be obtained from mud logging to support formation evaluation. Field data will help wellsite geologists, petrophysicist and reservoir engineers to predict reservoir quality, fluid contacts and reservoir permeability based on formation gases detected while drilling. This study discusses some examples from exploratory wells that have recently been drilled in Kuwait. Gas readings were recorded while drilling through deep Jurassic formations to evaluate hydrocarbon content using Advanced Gas Chromatography. The primary components of the system utilized are: a constant volume gas extractor, a gas sample flow control system, and a high resolution chromatographic system. To interpret the findings Gas readings are monitored by a complex system which provides real-time continuous measurements of the concentration of formation gases from very light components such as methane, to heavy components such as C6, C7 and C8 hydrocarbon species, comprising n-hexane, n-heptane, n-octane, benzene and toluene. Formation gas is considered as the first indication of a reservoir's fluid characterization and reflects the extent of the productivity of the well. Geochemical ratios and equations can enhance the interpretation of field data and give the first indication of zones of interest that need further evaluation. Dedicated flowmeter sensors (Coriolis) utilized to evaluate formation fractures while drilling. The Delta Flow trend versus time is characteristic of the type of losses and consequently of the downhole fractures. Geochemical ratios are plotted against depth and lithology to determine fluid type, contacts, fractures and dolomitization. For this purpose Well-Site Geochemical Package services, including X-Ray Fluorescence (XRF) and X-Ray Diffraction (XRD) workflow at rig site was also applied in of the wells. The analysis is based on measuring major and minor chemical mineralogy and elements of the drilled cuttings. This has helped in better quantitative assessment of different facies such as limestone, dolomite, shale etc., and providing a better control on geological model update while drilling the well. To take advantage of the field data, advanced mudlogging data are plotted on a depth log, which can be easily integrated with other data (post well data).

Distributed Temperature Sensor (DTS) technology uses fiber-optic cable to measure a continuous temperature profile along the wellbore. Compared to conventional production logging tools (PLT), DTS can provide operators real-time well information without intervention. Applications, from flow profiling to gas lift surveillance, have grown steadily in recently years. DTS applications require reliable data modeling and analysis or measurement interpretation. The complexity of the data analysis has been a barrier to DTS usage. This paper presents software tools developed for DTS interpretation. The model behind the software is based on steady-state energy balance, and it is applicable for gas and oil wells in both onshore and offshore environments. The software allows users to run in two modes: forward simulation and flow profiling. The forward simulation mode calculates the temperature distribution along the wellbore for any given production profile, and this mode is critical for the model calibration. It is also very useful for emulating "what-if" scenarios, such as forecast and gas lift surveillance. The flow profiling estimates the production profile based on measured temperatures, which is the basis for the real-time well monitoring. The model is tested against other models and good agreement has been obtained. This paper presents two examples: result comparison against TIPP, a computer program package developed by Chevron Corp, and a field example to verify gas lift valve operation.

A major factor in the success of a miscible hydrocarbon enhanced oil recovery process is the phase behaviour relationship between the injection and reservoir fluids. This paper describes the experimental procedures developed at Gulf Canada R&D to generate phase equilibrium data for specific reservoirs. The data have been applied in evaluating the potential for enhanced recovery in a number of Western Canadian carbonate reservoirs. The over-all procedure for a complete phase equilibrium study is described. This comprises field sampling, reservoir fluid characterization, injection fluid preparation, development of phase envelopes and correlation of phase behaviour. An integral part of the program involved the development Of a combination of analytical and high-pressure techniques to facilitate the rapid accumulation of vapour-liquid equilibrium data for reservoir-injection fluid systems. The Peng-Robinson equation of state and a new K value correlation were used successfully to rationalize the measured data. Experimental phase behaviour measurements in conjunction with appropriate correlation methods have proved valuable in tailoring the design of injection fluids to meet both miscibility requirements and economic constraints. Introduction Recent reports(1,2) have indicated that the use of enhanced recovery methods can increase Canada's available conventional oil reserves by approximately 2 to 3 billion barrels. Up to 95% of the additional oil with an API gravity greater than 25º could feasibly, and economically, be recovered using currently available miscible displacement techniques involving injection into the reservoir of either CO2 or hydrocarbon fluids. Realizing this potential, Gulf Canada Resources Inc. have been actively pursuing a program of initiating limited full-scale enhanced recovery projects and implementing pilot-scale floods(3) at various locations in Western Canada. To date, because of the types of reservoirs considered primarily carbonate and the local availability of suitable injection fluid components, attention has centred on the process of hydrocarbon miscible displacement. In support of these projects, the Gulf Canada R&D Department has developed an extensive experimental program to provide data both for preliminary screening of candidate reservoir and injection fluids and for detailed design of optimum injection fluids in specific reservoirs. This paper describes the experimental program that has evolved during application to such projects over the past five years. Miscible Displacement The residual oil saturation, after primary and secondary production of a reservoir, is a function of the formation geometry and the interfacial tensions of the fluids occupying the formation. The purpose of the injection fluid in enhanced recovery is to access the residual oil, and, by modifying the balance of interfacial tensions, to mobilize the residual oil to production. In miscible displacement processes, as the name implies, this purpose is achieved when miscibility is attained between the displacing fluid (injection fluid) and the residual oil, thereby eliminating the interfacial tension between the two. The miscibility of an injection fluid and reservoir oil is governed by the phase behaviour which is unique to each specific combination. The relationship between phase behaviour, miscibility and composition at reservoir temperature and pressure is illustrated on the pseudo-ternary Point R is the reservoir fluid composition and X represents the critical composition or plait point.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 194284, “Pushing the Limits of Damage Identification With Coiled Tubing in Extreme Conditions: A Success Story From Japan,” by Nozomu Yoshida, SPE, Satoshi Teshima, SPE, and Ryo Yamada, INPEX, and Umut Aybar, SPE, and Pierre Ramondenc, SPE, Schlumberger, prepared for the 2019 SPE/ICoTA Well Intervention Conference and Exhibition, The Woodlands, Texas, USA, 26–27 March. The paper was peer reviewed and is scheduled for publication in SPE Production & Operations. The success of water-conformance operations often depends on clear identification of the water-production mechanism. Such assessment can be complicated significantly when formation damage is also occurring. Coiled tubing (CT) and distributed temperature sensing (DTS) were combined to overcome challenging conditions (high temperature, low injectivity, high deviation, long perforated intervals, and wellbore damage) to identify damaged oil zones and suspected water-bearing zones in an onshore well in Japan. Introduction Source and location affect the selection of water-shutoff techniques, which are either mechanical or chemical in nature or a combination. No matter the operational approach, identification of the water zone is a critical step for any subsequent course of actions. One method for the identification of water-producing zones is the use of production logging. Conventional production logging uses spinners and capacitance logs to detect water flow in the wellbore. Production logging tools (PLTs) can be deployed into the wellbore using slickline, wireline, or CT. To enable real-time evaluation of the acquired data, possible options include wireline, digital slickline, and CT equipped with either a conductor cable or fiber optics. In damaged wells with high water cut, flow conditions can be unstable, with drastic changes in flow regimes. Once the well can no longer sustain stable flow because of reservoir depletion or damage in the absence of an artificial-lift method, a PLT becomes impractical. Furthermore, when wellbore conditions are complicated by the presence of debris or contaminants, data acquisition itself becomes difficult. Quantification of the damage profile and of water-producing intervals is of great importance in proper planning for subsequent operations. To address these challenges, an alternative approach was used wherein DTS obtained through fiber optics deployed with CT was used to quantify damage profiles in severely damaged wells and to identify suspected water-bearing zones by integrating complementary information. The proposed operational procedures are similar to those used for the quantification of fluid placement during acidizing operations: injection of fluid to cool down the formation and shut-in to measure rate and amplitude of temperature recovery along intervals of interest. In the present case, brine was used as the injection fluid. Quantification of the damage and injection-rate profiles are achieved by temperature inversion; the measured DTS data are matched with the simulated temperature response given by combined flow and thermal numerical models accounting for key formation and near-wellbore parameters. The subject well was suspected to be severely damaged during the completion phase and yielded a relatively high water cut during flow test. This case not only highlights the validity of the proposed approach but also details the work flow and analyses performed to obtain meaningful data and to reduce uncertainty of the interpretation. The work also raises the importance of the integration of complementary data for a comprehensive understanding of well conditions.

Fluid characterization is a key input into reservoir and field development studies and effective wells and reservoir management. Thus, the importance of acquiring representative reservoir fluid samples cannot be over emphasized. Fluid samples acquired from the reservoir may be contaminated by drilling fluid. However, with advancements in reservoir fluid analysis and characterization, it is possible to numerically clean contaminated reservoir fluid samples. This paper presents a case study of the effects of Oil-based drilling Mud (OBM) contamination on gas condensates fluid properties from a Deepwater turbidite reservoir in Nigeria. Four contaminated samples acquired from this reservoir were studied. The results show that drilling fluid contamination has a marked effect on key gas condensate fluid properties such as the Condensate-Gas-Ratio (CGR). The higher the contaminant the higher the CGR of the contaminated and resultant cleaned fluid. Numerical cleaning of OBM contaminated gas condensates does not guarantee obtaining a fluid model that is representative of insitu uncontaminated reservoir fluid. A linear relationship was observed between the cleaned fluid CGR and Saturation Pressure (Psat) with respect to the contamination level. Extrapolation of this relationship to 0% wt. contamination yields a CGR and Psat that were likely to be indicative of insitu uncontaminated fluid CGR and Psat. This formed the basis for a low case PVT parameter estimate, thus enabling the definition of suitable fluid parameter uncertainty ranges. The paper also highlights the importance of acquiring multiple fluid samples and benchmarking fluid description against possible analogues within the same and/or similar geological setting to enable the development of possible insights that may support and improve the analysis.

The relentless pursuit of well integrity is a critical mission in the oil and gas industry, especially in mature fields where the risks of casing leaks loom large. This study from Kuwait highlights the necessity of constant vigilance to proactively tackle these leaks, which threaten both production efficiency and environmental safety. Emphasizing early leak detection, this research aims to demonstrate how advanced methodologies can significantly reduce the costs and risks associated with extensive workover operations and the potential need for well suspension or abandonment. The focus lies in accurately identifying and quantifying casing leaks, including their depth and directional flow, crucial for effective well diagnostics and integrity management. This study introduces a cutting-edge approach for pinpointing casing leaks in wells, especially those with simpler completion designs. It showcases the deployment of an optical fiber-enabled coiled tubing system to implement distributed temperature sensing (DTS). This innovative combination enables real-time downhole measurements, including pressure and casing collar locator (CCL) readings for precise depth determination. The key advancement here is the ability to capture temperature anomalies in real-time, offering a comprehensive and dynamic profile of both the borehole environment and the surrounding formation. This approach represents a significant leap forward in well diagnostics technology. In a North Kuwait oil-producing well with a deviated trajectory, conventional production logging tools (PLT) were inadequate in locating a casing leak. Utilizing well hydraulics analysis, the DTS technology, facilitated by fiber optics-equipped coiled tubing, was employed. Different operational stages were correlated through a series of DTS surveys, ultimately leading to the successful identification of the leak. Notably, this operation was performed without a rig, incorporating a novel nitrogen injection workflow to stimulate leak production. This approach, a first of its kind, marked a shift in industry practices. The precision of this Coiled Tubing and fiber optic system in detecting temperature variations at the influx point was unprecedented, showcasing the method’s effectiveness. This case study offers invaluable insights into leveraging DTS in conjunction with Coiled Tubing for diagnosing completion leaks. The innovative strategy of nitrogen injection via the annulus of the kill string, enhancing fluid column visibility and inducing wellbore production, while simultaneously monitoring temperature shifts, represents a significant breakthrough. This approach not only confirms the leak location with enhanced accuracy but also adds a new layer to the standard DTS protocol. It sets a new benchmark for industry practices in leak detection and well integrity assurance.

Distributed Acoustic Sensing (DAS) and Distributed Temperature Sensing (DTS) measurements are technologies which are adding some benefits in the aim to replace or complete traditional logging measurements like noise logging tools (NLT) or production logging tools (PLT). The aim of well integrity interventions using distributed fiber optic sensing (DFOS) is to significantly reduce the duration and the cost of these operations, and to provide additional information in comparison to traditional logging tool. The combination of DAS and DTS can offer both qualitative and quantitative information regarding fluid dynamics in the context of well integrity investigation, as the flow characteristics (intensity of turbulences). In addition to acoustic (high frequency DAS) and temperature (DTS) monitoring for leak detection, we propose to use DTGS (Distributed Temperature Gradient Sensing) with low frequency DAS (< 1 Hz) to monitor leaks on the completion tubing of a well. The main advantage of using DTGS with DAS is its sensitivity to small leaks, including the direction of propagation of the leak.

Distributed Fiber optic sensing system is a unique tool for the evaluation of distributed temperature over several kilometers. It is a powerful diagnostic instrument for the identification and localization of potential problems, such as leakages in pipelines and dykes, hot-spots in high-voltage cables and other events that create temperature anomalies. Such distributed temperature sensing (DTS) systems have the advantage of being relatively easy to deploy over long pipeline sections and have been shown to detect leakages events with good accuracy and reliability. However, when distributed fiber optic sensing systems are deployed in security-critical applications, where availability and reliability are crucial, it is important to continuously verify and assess the correct functioning and reliability of the whole system, including the sensing cables, the measurement system, the data analysis software and the alert transmission. In the past, such testing have been performed periodically by the pipeline personnel, but testing frequencies are typically low, e.g. once per year. The DTS Automated Trip Testing System is a fully independent device that is able to produce a controlled and localized thermal anomaly (hot spot or cold spot) and verify its correct detection. This allows a continuous verification of the DTS system reliability and functionality and a periodic statistical evaluation of the confidence level (proven by experience SIL rating). This paper will present more specifically the development, the functioning and deployment, and its applications of an automated system and method for testing the efficacy and reliability of distributed temperature sensing (DTS) systems, in particular those DTS systems used for pipeline leakage detection.

This study relates the chemical composition of the polar compounds of crude oil to the wettability of rock/oil/brine systems. Adsorption properties of polar and asphaltene fractions were evaluated to determine their effects on wettability. Polar compound fractions were found to cause an oil-wet state on Berea sandstone, but the effects were not a function of the polar-fraction concentration. The concentration of nitrogen/sulfur compounds in six crude-oil polar fractions correlated with the wettability of the polar fractions on Berea sandstone. Langmuir-type adsorption on Berea sandstone was observed in adsorption studies of the asphaltene and polar fractions. Additional analysis with brien-saturated Berea sandstone resulted in adsorption values up to three times less than that for dry Berea. The amount of polar fraction adsorbed on brine-saturated berea sandstone correlated with crude-oil wettability.

Electromagnetic (EM) waves are used in the oil and gas industry to identify the geology of the formation and the type of the fluid saturating the medium. There is also an interest to use the electromagnetic waves as an enhanced oil recovery (EOR) method. However, interpretation of logging data generated through electromagnetic waves or determination of the electromagnetic wave propagation in a medium as an EOR method are not easy tasks. This study aims to identify the role of different geological settings with different types of fluid saturations in the response of electromagnetic wave propagation and absorption. To reach this objective multitude-systematic laboratory scale experiments were conducted on different reservoirs fluid and rock pairs. As reservoir mineralogy, different grain size of quartz, clay, or limestone is used to prepare the reservoir rocks at different porosity. Water is known as a good absorber for EM waves, thus, pore space were saturated at different water saturations and a bitumen sample (10,000 cP, 12° API) from Canada. Prepared samples were packed into in-house-built-Plexiglas core holder which allows measurements with EM waves. The response of EM waves propagation and absorption was measured by using a vector network analyzer at varying frequencies (500 MHz to 4 GHz) through dielectric properties (dielectric constant, loss tangent, and penetration depth). The results were used to obtain correlations between dielectric properties and physical properties (reservoir rock mineralogy, porosity, water saturation, and oil saturation) of the reservoir rock-fluid blends. Water saturation gives a perfect correlation with dielectric constant and loss tangent values of the saturated medium. Because dielectric constant and loss tangent parameters provide an idea on the absorption characteristics of EM wave in the medium, and because water is a strong EM wave absorber, as it was expected, with the increase in water saturation, the dielectric constant and loss tangent parameters of the medium are also increased; on the other hand, penetration depth was decreased. With the increase in quartz content in the medium, it has been observed that EM wave penetration is enhanced. As a result, several correlations were created in this study and they can be used to better interpret the reservoir mineralogy and fluid saturation as a response to EM wave logging. Moreover, these results can be used to estimate the effective area (penetration depth) of EM wave as an EOR method in different mediums.

Reservoir fluid properties play a key role in the design and optimization of production processes and facilities for efficient reservoir management. Inaccurate and unreliable fluid characterization leads to high uncertainties in in-place hydrocarbon volume estimates, negatively impacting ultimate recovery predictions and hence the asset value. Obtaining reliable PVT properties of reservoir fluids starts with the acquisition of adequate volumes of representative fluid samples followed by PVT data measurement and phase behavior modeling. Subsequent laboratory analysis should be monitored through established quality control procedures to provide high quality data. The fluid characterization methodology should employ best-practice techniques to model fluid behavior as functions of pressure, temperature, and fluid composition. In this paper, we discuss key steps in sampling and fluid characterization for a wide spectrum of fluid types ranging from extra-heavy oils to lighter gas-condensates including complex near-critical fluids. Using several field examples, sampling tool design and procedures for obtaining representative samples are discussed. Laboratory fluid analysis strategies for various fluid types are highlighted with an emphasis on employing quality control and quality assurance procedures. The importance of special PVT tests to capture fluid behavior under different production strategies ranging from simple depletion to complex tertiary recovery is emphasized. Application of recommended fluid modeling techniques such as C7+ characterization and Gibb's energy minimization are demonstrated through field examples.