Static Formation Temperatures Research Articles

Integrated coupled assessment of geostorage and geothermal prospects in the oil fields of Upper Assam Basin

This study proposes an integrated approach of assessing CO2 storage potential and geothermal energy prospect based on the data of seventeen depleted wells of Upper Assam Basin which could assist the global objective of net zero transition. The petrophysical properties of Tipam, Barail and Lakadong + Therria Formations from the seventeen wells have been utilised to perform the Monte Carlo simulation for probabilistic estimation of the CO2 storage in the Upper Assam Basin. This preliminary work showed that the mean storage capacity of 18.8 ± 0.7 MT, 19.8 ± 0.9 MT and 4.5 ± 0.8 MT could potentially be stored in the three geological formations of the basin. The corrected bottom hole temperature values for the studied seventeen wells were determined using the well log data and Waples and Harrison method; these values provided a static geothermal gradient for each well, which varies widely from 0.017 to 0.033 °C/m. In order to enable geothermal prospectivity, static formation temperature maps have been generated for the studied wells. The probabilistic assessment of stored heat-in-place and formation temperature maps delimited five prospective sites for the extraction of geothermal energy in the basin. The study also presented a risk assessment for CO2 storage development in the basin. Further, the study illustrated an economic analysis of the implementation of a CO2 storage project and geothermal operations in the basin.

Temperature transient analysis: Static formation temperature test (SFTT) an overview

When drilling a geothermal well, obtaining real-time measurements of the static formation temperature is impractical due to the cooling effect of drilling fluids on the surrounding rock, which masks the actual reservoir temperatures. To overcome this, the site engineers undertake a static formation temperature test (SFTT) to ascertain the stable reservoir temperature. The present work reviews existing methods for analysing data using five different temperature sets sourced from published literature. Based on our analysis, we provide recommendations on the application of the various analytical techniques. We recommend utilising the spherical method when using bottom-hole data, whilst, for any other depth, we recommend one of the cylindrical methods. These recommendations aim to enhance the accuracy and reliability of SFTT assessments during geothermal well drilling operations.

Application of Artificial Intelligence in Static Formation Temperature Estimation

Application of Artificial Intelligence in Static Formation Temperature Estimation

Wireline Logging Operation Uses Water-Based Drilling Fluid in HP/HT Gulf of Mexico Well

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 210021, “Wireline Logging in High-Overbalance, High-Pressure/High-Temperature Deepwater Gulf of Mexico Well With Water-Based Reservoir Drilling Fluid,” by Martin Tjioe, Jeremy McCaslin, and Jonathan J. Brege, SPE, Shell, et al. The paper has not been peer reviewed. _ Openhole wireline logging, because of its lower overpull capacity relative to logging while drilling, is subject to increased stuck-tool risk. The risk increases in higher-overbalance environments typical for depleted reservoirs, but other aspects of sticking risk can be managed. The complete paper describes the measures taken in an openhole wireline-logging operation in a deepwater Gulf of Mexico (GOM) well under nearly 7,000-psi overbalance in a high-pressure/high-temperature (HP/HT) slimhole environment using water-based reservoir drilling fluid (RDF) to achieve an efficient logging operation without incurring lost time attributed to conveyance-related issues. Introduction The wireline data-acquisition program was planned for an injector well in the deepwater GOM development field. The goal of the well was to maintain reservoir pressure through waterflooding, maximize recovery, and appraise the downdip portion of the fault block. The target was an aeolian sandstone reservoir at a depth of approximately 25,500 ft total vertical depth subsea featuring 19% porosity and permeability in the tens-of-millidarcy range. The reservoir had depletion of 6,850 psi; the well penetrated 174 ft of the reservoir with a hole size of 7 in. and a deviation of 25°. The injector used an openhole stand-alone-screen completion concept. Water-based RDF was used so that filter-cake material could be removed using a breaker fluid to enable matrix injection. Using a 13.5-lbm/gal mud weight, the wireline operation was performed under a downhole pressure of 17,900 psi (overbalance of 6,950 psi). The maximum temperature recorded during wireline was 320°F. Wireline Data-Acquisition Program The wireline program’s objectives were to acquire safely a profile of pressures and mobilities to identify depletion boundaries and to inform completion operations and acquire temperature data to infer the static formation temperature. During the planning phase, the well was classified as highly challenging, with a high risk of differential sticking based on the analog wireline jobs in the field. The well of interest penetrated the reservoir with the highest depletion encountered in the field at the time; because of its downdip location, it also had one of the higher downhole temperatures in the field. Several learnings from analog wells that are further detailed in the complete paper included the following: - Necessity of good hole cleaning - Reduction of toolstring length - Necessity of a water-based RDF with good fluid properties

Uncertainty Assessment of Corrected Bottom-Hole Temperatures Based on Monte Carlo Techniques

Most temperature predictions for deep geothermal applications rely on correcting bottom-hole temperatures (BHTs) to undisturbed or static formation temperatures (SFTs). The data used for BHT correction are usually of low quality due to a lack of information and poor documentation, and the uncertainty of the corrected SFT is therefore unknown. It is supposed that the error within the input data exceeds the error due to the uncertainty of the different correction schemes. To verify this, we combined a global sensitivity study with Sobol indices of six easy-to-use conventional correction schemes of the BHT data set of the Bavarian Molasse Basin with an uncertainty study and developed a workflow that aims at presenting a valid error range of the corrected SFTs depending on the quality of their input data. The results give an indication of which of the investigated correction methods should be used depending on the input data, as well as show that the unknown error in the input parameters exceeds the error of the individual BHT correction methods as such. The developed a priori uncertainty-based BHT correction helps to provide a real estimate of the subsurface temperatures needed for geothermal prospecting and probabilistic risk assessment.

Joint interpretation technology of favorable HDR geothermal resource exploration in Northern Songliao Basin

Hot dry rock (HDR) is considered a new clean and renewable energy source. China is rich in HDR resources, but viable and reliable resource evaluation techniques and exploration methods have not been available yet. This research method, consisting of deep exploration combined with shallow drilling, screens the geothermal anomaly regions using heavy magnetic, electric measurement, seismic and thermal joint interpretation technology, and verifies the geophysical multiplicity with massive oilfield drilling data to locate the favorable HDR target region. The research results show a regionally geothermal abnormal area. We use relative impedance combined with seismic profile to recognize the HDR target region. The geophysical exploration and geological joint interpretation technology are faster and more accurate than the single geophysical exploration technology. The comprehensive analysis believes that the high resistance granite body in the southern Paleo-central uplift zone, with its area 500km2, its thickness 150–330m, its static formation temperature reaching 152° in the depth of 3360m, its high rock thermal conductivity, its good deep fracture, and base fracture development, is a fragmented granite and weathered shell, easy for artificial reservoir re-constructing. There is high preciseness in locating the favorable target region for HDR development.

Uncertainty analysis of numerical inversions of temperature logs from boreholes under injection conditions

Abstract Conventional methods to estimate the static formation temperature (SFT) require borehole temperature data measured during thermal recovery periods. This can be both economically and technically prohibitive under real operational conditions, especially for high-temperature boreholes. This study investigates the use of temperature logs obtained under injection conditions to determine SFT through inverse modelling. An adaptive sampling approach based on machine-learning techniques is applied to explore the model space efficiently by iteratively proposing samples based on the results of previous runs. Synthetic case studies are conducted with rigorous evaluation of factors affecting the quality of SFT estimates for deep hot wells. The results show that using temperature data measured at higher flow rates or after longer injection times could lead to less-reliable results. Furthermore, the estimation error exhibits an almost linear dependency on the standard error of the measured borehole temperatures. In addition, potential flow loss zones in the borehole would lead to increased uncertainties in the SFT estimates. Consequently, any prior knowledge about the amount of flow loss could improve the estimation accuracy considerably. For formations with thermal gradients varying with depth, prior information on the depth of the gradient change is necessary to avoid spurious results. The inversion scheme presented is demonstrated as an efficient tool for quantifying uncertainty in the interpretation of borehole data. Although only temperature data are considered in this work, other types of data such as flow and transport measurements can also be included in this method for geophysical and rock physics studies.

Determination of Geothermal Gradient from Bore Hole Temperature data in Some Parts of the Eastern Niger Delta Basin

An analysis of Geothermal Gradients in the Eastern Niger Delta basin was done using Bore Hole Temperature (BHT) data from three (3) adjacent oil fields. BHT data was converted to static formation temperature by using the conventional method of increasing measured BHT data by 10% and Geothermal Gradient computed using its simple linear relationship with depth, surface temperature and static temperature at depth. Projections were then made for change in Geothermal gradients at 1km intervals to a depth of 4 km. Results obtained showed significant variations across Idama, Inda and Robertkiri fields with average geothermal gradients of 17.3⁰C/Km, 22.6⁰C/Km and 23.1⁰C/Km respectively. Variation in the geothermal gradients in the area is attributed to lithological control and differential rates of sedimentation during basin evolution. Also, results showed that the Geothermal Gradient in the area are generally moderate and could be a good reason for the occurrence of more oil hydrocarbons than gas in the area.

Simulation of Temperature in Gas Drilling with Gradient Method

Accurate prediction of gas temperature profile is critical for designing gas drilling operations. Traditionally the gas temperature distribution in wellbore is assumed to equal the static formation temperature where the influences of fluid flow and Joule-Thomson cooling effect have not been considered. This work presents a gradient equation method to predict the gas temperature profile in the wellbore with considerations of gas flow and Joule-Thomson local cooling at drill bit. The method applies equations of pressure, temperature, density and velocity to gas flow inside drill string and annulus. The solution of the gradient equations takes the form of the fourth order Runge-Kutta equation. Bottom hole temperature measurement from depth 700m to 2000m in a real well is found consistent with the temperature values predicted by the gradient method, both showing 20℃ ~ 30℃ temperature drop due to the Joule-Thomson cooling effect at the bit nozzles. Result of sensitivity analyses with the gradient method indicates that the temperature drops due to the Joule-Thomson cooling effect can be up to 50℃, depending on nozzle size. The steady temperature profile can be established within minutes of gas circulation. Because of the influences of gas flow and Joule-Thomson cooling, the gas temperature in the wellbore significantly deviates from the formation geothermal temperature in flowing conditions. The gas temperature in the drill string increases with the well depth and then decreases rapidly toward the bottom of hole. As the gas flows up the annulus, the gas temperature first jumps up, overshoots the formation temperature, and then gradually decreases along the geothermal gradient trend.

Customized Solutions for Coiled Tubing Interventions in the Bolivian Sub-Andean Basin

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202620, “A Review of 25 Coiled Tubing Well Interventions: Customized Solutions for Bolivian Sub-Andean Basin,” by Jovanny A. Hernandez, SPE, Luis F. Antelo, SPE, and Carlos D. Rodriguez, Halliburton, et al., prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually 9–12 November. The paper has not been peer reviewed. Fields in the Bolivian Sub-Andean Basin are remote and difficult to access. The producing zones include the country’s most challenging wells, with depths of up to 26,000 ft, with high pressure/high temperature (HP/HT), high gas cut, crossflow, dogleg severity, and well-access restrictions. The complete paper reviews 25 coiled tubing rigless well interventions (CTRWI) to extend the life of those wells, including operations involving nitrogen (N2) lift, acid wash, milling, shifting sleeves, setting packers, stimulation, velocity strings (VS), and fishing. Introduction CTRWI in Sub-Andean Basin fields had not been implemented historically because of limited road access to the fields, lack of available equipment with high technical capabilities, high pressure, and well depth. Beginning in 2017, however, operators evaluated the risk and elected to perform CTRWI involving stimulation, cleanout, N2 lift, fishing, VS jobs, and other techniques. Equipment with specialized capabilities was requested to address the operational requirements and the ability to travel on the remote roads while respecting transit regulations limiting maximum weight to 55 tons. The challenges to transporting equipment economically include - Transportation of large reels of 2⅞-in. coiled tubing (CT) string to complete dual-sectioned VS installations - Transportation of CT unit with 6,600 m of 1¾-in. CT string (weight of less than 55 tons) - Continuously moving large volumes of N2 to the field Wells in these fields were drilled no more than 10 years ago. The majority were built with smart completions, several production layers separated with swell packers and flowing through sliding sleeves configured with the same direction of actuation for opening and closure. Completions are configured with production tubing sizes of 7, 5, 4½, and 3 in. The tubing and accessories are made from chrome 13 because of the presence of carbon dioxide in the production fluids. The region includes some exploratory fields having HP/HT conditions and mature fields with declining production. These wells are important for both the operators and the local government because their production represents more than 50% of national production. On-Site Laboratory Testing Characteristics of produced formation water and mineralogy tests of water samples helped identify a calcium carbonate (CaCO3) scale type. Because CaCO3 scale is known to be acid-soluble, a tailored acid-treatment system was selected with a static formation temperature between 220 to 286°F. On-site laboratory tests using a combination of 13% acetic and 9% formic retarded acid treatment systems were applied to the samples obtained, and results of a solubility test were observed. The selected treatment was demonstrated to be highly effective at dissolving CaCO3 scale according to the test made at the wellsite. High confidence was placed in the test results of the acid-treatment sample because dissolution was above 85% in a 4-hour test period under static well temperature.

Horner Analysis for Negative Inflow Tests of Well Barriers

SummaryNegative tests, or inflow tests, are conducted to verify the integrity of well barriers in the direction of potential flow, subjecting a barrier to a negative pressure differential, while monitoring for signs of a leak. A common practice is to observe the rate of flowback from the well. Flowback may be a sign of a leak due to an influx of formation fluids into the well. However, even when there is no leak, flowback is commonly observed due to thermal expansion of wellbore fluids. Heat transfer will occur between the wellbore fluids in each annulus and with the surrounding formation until temperatures reach an equilibrium. This behavior is described by the process of thermal diffusion, with the resulting temperature increase causing expansion of wellbore fluids and flowback from the well.Industry guidelines state “Horner” analysis may be used when monitoring flowback or pressure buildup during an inflow test. In doing so, engineers and wellsite supervisors may use a “Horner plot” to determine if flowback or pressure buildup is attributable to thermal effects. Those without a reservoir engineering background may not be aware the method was originally derived from a radial flow equation for the purpose of monitoring pressure buildup in a well when shut in after a period of production. The apparent similarity of the radial flow and thermal diffusion equations is what led Horner's technique to subsequently be applied to the prediction of static formation temperature from well logs. However, although thermal expansion is a function of formation temperature, Horner analysis of flowback or pressure buildup during an inflow test has remained a black box that is poorly understood.For the first time, with support from empirical data from offshore wells, we reveal that Horner analysis of thermal expansion is a practice without theoretical justification. The radial equation on which Horner analysis depends, along with the constraints implied by the boundary conditions, fails to accurately account for the conditions of an inflow test. As a result, the method should not be used for analyzing flowback or pressure buildup during an inflow test. Instead, a new method is proposed to interpret a trend of flowback when monitoring well barriers. The findings of this study can help improve understanding Horner analysis and techniques for interpreting inflow tests.

Temperature log simulations in high-enthalpy boreholes

Temperature logs have important applications in the geothermal industry such as the estimation of the static formation temperature (SFT) and the characterization of fluid loss from a borehole. However, the temperature distribution of the wellbore relies on various factors such as wellbore flow conditions, fluid losses, well layout, heat transfer mechanics within the fluid as well as between the wellbore and the surrounding rock formation, etc. In this context, the numerical approach presented in this paper is applied to investigate the influencing parameters/uncertainties in the interpretation of borehole logging data. To this end, synthetic temperature logs representing different well operation conditions were numerically generated using our newly developed wellbore simulator. Our models account for several complex operation scenarios resulting from the requirements of high-enthalpy wells where different flow conditions, such as mud injection with- and without fluid loss and shut-in, occur in the drill string and the annulus. The simulation results reveal that free convective heat transfer plays an important role in the earlier evolution of the shut-in-time temperature; high accuracy SFT estimation is only possible when long-term shut-in measurements are used. Two other simulation scenarios for a well under injection conditions show that applying simple temperature correction methods on the non-shut-in temperature data could lead to large errors for SFT estimation even at very low injection flow rates. Furthermore, the magnitude of the temperature gradient increase depends on the flow rate, the percentage of fluid loss and the lateral heat transfer between the fluid and the rock formation. As indicated by this study, under low fluid losses (< 30%) or relatively higher flow rates (> 20 L/s), the impact of flow rate and the lateral heat transfer on the temperature gradient increase can be ignored. These results provide insights on the key factors influencing the well temperature distribution, which are important for the choice of the drilling data to estimate SFT and the design of the inverse modeling scheme in future studies to determine an accurate SFT profile for the high-enthalpy geothermal environment.

Toward a global model for correction of bottomhole temperature data: Progress and limitations

Static formation temperature (SFT) can be estimated from temperatures measured during wire-line logging (Tm). A large number of correction models for obtaining SFT from Tm have been suggested. Several studies have shown that SFTs yielded by such models are off by an average of 6°C–10°C (43°F–50°F) at burial depths of 1.5–3.5 km (0.9–2.2 mi) and thus have the potential to cause serious issues in thermal and hydrocarbon generation models. This paper explores the causes for erroneous SFT predictions generated from Tm measurements and identifies factors that should be addressed to generate a globally applicable correction model. We also present an improved empirical correction model for Tm data from eight oil and gas fields, located on the Norwegian continental shelf. The new empirical model was designed to give correct average SFT predictions and is applicable to single Tm measurements. It has been validated against temperatures recorded during drill-stem testing, which closely represent local SFTs. The expression yields improved results compared with other correction models applied to the data set. However, the average error in computed SFT values varies by up to 10°C (18°F) between the investigated hydrocarbon fields. We conclude that these variations result from differences in operational practices such as fluid circulation and drilling velocities. Therefore, current empirical and physical models for SFT prediction from Tm require local calibration. It is also suggested that more accurate compilations and analyses of operational data could lead to improved and more globally applicable models.

The Geothermal Regime in Sirt Basin, Libya: The Geological Role and Heat Flow Studies

Bottom hole temperatures (BHTs) and static formation temperatures (DSTs) of 70 deep exploratory wells are used to evaluate the geothermal regime in the northeastern part of Sirt Basin. A linear regression was derived between the BHT’s and the DST’s, for correcting the bottom hole temperatures from the drilling factors that lower them from the true formation temperatures. The geothermal gradients were calculated using the corrected BHT’s and the heat flow has been estimated. Interpretation of the geothermal data, utilizing subsurface maps and isothermal geologic cross section, revealed a shallow, local semi-thermal reservoir of Oligo-Miocene age (at depths 1000 m). The geothermal gradients and heat flow values of this reservoir are ranging from 40 - >60°C/Km and from 80 up to >130 mW/m2, respectively. At deeper depths (>1000 m until the maximum depth of investigation), the area has more or less moderate to low geothermal gradients that range from 40 to 2. The study indicates that the vertical and the lateral variations of the formation temperatures, geothermal gradients and the heat flow values are controlled by the structural, groundwater movements as well as lithological and thermal characteristics of the subsurface sequence.

A 3-D wellbore simulator (WELLTHER-SIM) to determine the thermal diffusivity of rock-formations

Acquiring thermophysical properties of rock-formations in geothermal systems is an essential task required for the well drilling and completion. Wellbore thermal simulators require such properties for predicting the thermal behavior of a wellbore and the formation under drilling and shut-in conditions. The estimation of static formation temperatures also needs the use of these properties for the wellbore and formation materials (drilling fluids and pipes, cements, casings, and rocks).A numerical simulator (WELLTHER-SIM) has been developed for modeling the drilling fluid circulation and shut-in processes of geothermal wellbores, and for the in-situ determination of thermal diffusivities of rocks. Bottomhole temperatures logged under shut-in conditions (BHTm), and thermophysical and transport properties of drilling fluids were used as main input data. To model the thermal disturbance and recovery processes in the wellbore and rock-formation, initial drilling fluid and static formation temperatures were used as initial and boundary conditions. WELLTHER-SIM uses these temperatures together with an initial thermal diffusivity for the rock-formation to solve the governing equations of the heat transfer model. WELLTHER-SIM was programmed using the finite volume technique to solve the heat conduction equations under 3-D and transient conditions. Thermal diffusivities of rock-formations were inversely computed by using an iterative and efficient numerical simulation, where simulated thermal recovery data sets (BHTs) were statistically compared with those temperature measurements (BHTm) logged in some geothermal wellbores.The simulator was validated using a well-documented case reported in the literature, where the thermophysical properties of the rock-formation are known with accuracy. The new numerical simulator has been successfully applied to two wellbores drilled in geothermal fields of Japan and Mexico. Details of the physical conceptual model, the numerical algorithm, and the validation and application results are outlined in this work.

Static Formation Temperature Prediction Based on Bottom Hole Temperature

Static formation temperature (SFT) is required to determine the thermophysical properties and production parameters in geothermal and oil reservoirs. However, it is not easy to determine SFT by both experimental and physical methods. In this paper, a mathematical approach to predicting SFT, based on a new model describing the relationship between bottom hole temperature (BHT) and shut-in time, has been proposed. The unknown coefficients of the model were derived from the least squares fit by the particle swarm optimization (PSO) algorithm. Additionally, the ability to predict SFT using a few BHT data points (such as the first three, four, or five points of a data set) was evaluated. The accuracy of the proposed method to predict SFT was confirmed by a deviation percentage less than ±4% and a high regression coefficient R2 (&gt;0.98). The proposed method could be used as a practical tool to predict SFT in both geothermal and oil wells.

A new empirical method based on log-transformation regressions for the estimation of static formation temperatures of geothermal, petroleum and permafrost boreholes

A new empirical method based on log-transformation regressions for the estimation of static formation temperatures of geothermal, petroleum and permafrost boreholes

RPM-WEBBSYS: A web-based computer system to apply the rational polynomial method for estimating static formation temperatures of petroleum and geothermal wells

A Web-Based Computer System (RPM-WEBBSYS) has been developed for the application of the Rational Polynomial Method (RPM) to estimate static formation temperatures (SFT) of geothermal and petroleum wells. The system is also capable to reproduce the full thermal recovery processes occurred during the well completion. RPM-WEBBSYS has been programmed using advances of the information technology to perform more efficiently computations of SFT. RPM-WEBBSYS may be friendly and rapidly executed by using any computing device (e.g., personal computers and portable computing devices such as tablets or smartphones) with Internet access and a web browser. The computer system was validated using bottomhole temperature (BHT) measurements logged in a synthetic heat transfer experiment, where a good matching between predicted and true SFT was achieved. RPM-WEBBSYS was finally applied to BHT logs collected from well drilling and shut-in operations, where the typical problems of the under- and over-estimation of the SFT (exhibited by most of the existing analytical methods) were effectively corrected.

Improved method for estimating static formation temperatures in geothermal and petroleum wells

This paper describes a mathematical method for estimating static formation temperatures using a function based on extrapolation of the measured data in the thermal recovery process of geothermal and petroleum wells. This method uses the least squares fit of a rational polynomial model to describe the transient temperature data and also provides an analytical expression of thermal recovery processes. This expression gives the asymptotic value for final temperature. We then apply this method for estimating static formation temperatures of a geothermal and petroleum drilled well.In this work we have developed the equations of least squares fit of rational polynomial function and used the equation to estimate the uncertainties of its coefficients. This fitting procedure allows us to obtain a mathematical model that represents the thermal recovery process and to extrapolate the value of final temperature. This is a practical method to estimate static formation temperature, having the advantages that the thermal properties of the drilling mud and its formation are not required; it can also be used in the geothermal and petroleum industries.

Thermal effect on wellbore stability during drilling operation with long horizontal section

In this study, a three-dimensional wellbore stability model is presented that takes into account thermal stresses combined with an integrated circulation temperature model for horizontal well drilling, the bottom hole temperature simulation were then validated using field measurements, and compared with results for vertical wells. A subsequent analysis of temperature sensitivity revealed that the heat source term, the length of horizontal section and mud specific heat were the main reasons cause the bottom hole temperature for horizontal wells rises above the static formation temperature. Results from the wellbore stability model show that the temperature variation magnitude in horizontal well is smaller than that in vertical wells, however, the effect of thermal stress on critical mud weight window in horizontal is more sensitive. The wellbore at toe of horizontal section is more stable than that at heel of horizontal section when the bottom hole temperature exceeds the static formation temperature. This research can provide a theoretical reference for enhancing overall operational efficiency and safety for horizontal well drilling.