Bottom-hole Temperature Research Articles

Controls on petroleum stability in deep and hot reservoirs: A case study from the Tarim Basin

Petroleum stability varies greatly among different basins with light oil recently being produced from reservoirs at depths up to 8260 m and present bottom hole temperatures up to 171 °C in the Tarim Basin. Determining the extent of oil-gas conversion (EOGC) and its controls are crucial to the “exploration deadline” of temperature or depth for liquid hydrocarbons. For this purpose, about 90 oils from the Cambrian and Ordovician in the Tarim Basin have been analyzed for biomarkers, diamondoids and thiadiamondoids, and their gas/oil ratios were collated. These oils have EOGC from 45.4 to 98.3% for TSR-altered oils in the Tazhong and Shunbei areas, and only 0–49.2% for all other non-TSR oils. Among non-TSR-altered oils, Tazhong oils show higher EOGC values (28.0–49.2%) than those in Tabei (0–9.7%) and Shunbei (0–32.7%) oils, respectively. We propose that higher heating rates (7 °C/Ma) and shorter durations (<5 Ma) at high temperatures (>150 °C) may account for the lower EOGC values of oils in the Tabei and Shunbei areas than those in the Tazhong with values of 0.1 °C/Ma and 250 Ma (>120 °C), respectively. The oil may be completely converted to methane-dominated gas if it was exposed to high temperatures for a longer duration as exampled from gas pools from the Lower Cambrian in the Sichuan Basin. In this case, the oil was heated at a rate of 1 °C/Ma since the oil charge and experienced >200 °C for about 50 Ma. Thermochemical sulfate reduction may have enhanced the conversion of oil to gas, leading to an increase in EOGC values from 30% for non-TSR-altered oils to 98% for the strongly TSR-altered oil in the eastern Tazhong area with similar burial-heating history. A similar case for elevated EOGC due to TSR can be found in the Smackover Formation, Gulf of Mexico. Thus, two global models related to heating rate and duration at high temperatures and TSR are developed to illustrate oil stability with temperature and are expected to be instructive for deep petroleum exploration.

Oil-well lightweight cement slurry for improving compressive strength and hydration rate in low-temperature conditions

Inadequate early compressive strength is a common problem when employing lightweight cement (LWC) slurries during the cementing of oil wells under low-temperature conditions. A new formulation of LWC slurry was investigated by the Research Institute of Petroleum Industry (RIPI) to improve the compressive strength and hydration rate of LWC slurries in low-temperature conditions. In this study, bottom-hole static temperature (BHST) ranges from 21 °C to 82 °C. Halliburton cement friction reducer (CFR-3), Litefil microspheres (D-124), hydroxy ethyl cellulose (D-112), styrene butadiene latex (D-600), and high strength hydrophobic silica (HSL-2) were as lightweight additives to make the RIPI-LWC formulation. The results showed that adding more 5 g of HSL-2 nanoparticles causes in a low-density cement slurry from 1442 kg/m3 to 1281.5 kg/m3. Besides, at the temperature of 21 °C, the strength value (i.e., 3.5 MPa @ 3:56 h)) was developed much faster than the temperature of 82 °C (i.e., 3.5 MPa @ 20:48 h), providing more significant insights into applying the proposed lightweight cement by reducing curing time. Furthermore, the hydraulic bonding of cement slurry was increased by attention to the action of thixotropic additive in preventing the gas migration from the cement slurry. The involvement of the new RIPI-LWC implies that cement columns can be pumped higher in the annulus, multiple-stage cementing becomes unnecessary without reducing cement integrity, and it is more economical and cost-effective than previous RIPI formulations.

Transformer-Based Models Aid Prediction of Transient Production of Oil Wells

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 206537, “Development of Deep Transformer-Based Models for Long-Term Prediction of Transient Production of Oil Wells,” by Ildar R. Abdrakhmanov, Evgenii A. Kanin, SPE, and Sergei A. Boronin, Skolkovo Institute of Science and Technology, et al. The paper has not been peer reviewed. _ The authors of the complete paper propose a novel approach to data-driven modeling of transient production of oil wells, applying transformer-based neural networks trained on multivariate time series composed of various parameters of oil wells measured during exploitation. By tuning machine-learning models for a single well (ignoring the effect of neighboring wells) on open-source field data sets, the authors of the paper demonstrate that the transformer-based method outperforms recurrent neural networks (RNNs) with long- and short-term memory (LSTM) and gated recurrent-unit cells in the forecasting of bottomhole pressure dynamics. Introduction The authors apply a novel deep-learning algorithm called a transformer to build surrogate models for simulations of well performance. Transformer architecture initially was developed for natural-language processing problems. However, in recent years, researchers have adapted transformers for time-series forecasting. In contrast with RNNs, the transformer does not process data sequentially. Instead, it handles the entire sequence by a multihead self-attention mechanism. The transformer is much more computationally efficient than an RNN because its training can be performed using graphics processing units. Transformer networks allow for application of the transfer-learning technique. First, the model is trained to predict the target parameter (e.g., bottomhole pressure) using the production data from a certain well. Next, the tuned weights are used to initialize the training procedure on the data from a target well. In other words, the fine-tuning is performed based on the pretrained model. The described technique allows the model to transfer knowledge from one time-series forecasting problem to another, leading to acceleration of the training process and improvement of model-prediction capability. The recurrent networks are not well-suited for transferring learning because the hidden state of recurrent cells is not transferred commonly. Problem Formulation The authors consider a transient production of an oil well with arbitrary completion. In most cases, various parameters of the well are measured during its exploitation, including bottomhole and wellhead pressure and temperature, flow rates for each phase, choke size, and parameters of electric centrifugal pumps (if available). In this case, the authors propose an alternative approach to find the dependence between bottomhole pressure and flow rate that is based on deep-learning algorithms trained on available field data and that allows for obtaining quick predictions of bottomhole pressure or flow rates. The data-driven coupled model of a well and reservoir can be used to plan and optimize the production process. Also, the developed model can be used to estimate well and formation properties using a constant flow-rate response of a well.

Generation temperatures for oils sourced from sulfur-rich kerogens using aromatic and light hydrocarbon isomers

Isomer ratios of certain hydrocarbons change with temperature, and this relationship can be used as a parameter for assessing thermal maturity and guiding petroleum exploration. The C7 dimethylpentanes (DMPs) are frequently used in the literature to calculate a temperature of generation for produced oils. These light hydrocarbons are extremely useful, when present, but can also be affected by source mixing, thermochemical sulfate reduction, water washing, and evaporative fractionation. The accurate calculation of temperatures is especially important for oils sourced from sulfur-rich kerogens (i.e., Type II-S) as the onset of oil generation commences at lower temperatures due to early cracking of carbon bonds. Due to the sulfur enrichment of kerogen, standard maturity methods may overestimate the thermal maturity of Type II-S oils; therefore, alternative methods specific to sulfur-rich sources, such as the aromatic methyldibenzothiophene (MDBT) isomers, are needed to accurately calculate generation temperatures and maturity. Studies linking light hydrocarbons to larger-chained aromatic hydrocarbons are limited. This study integrates the light hydrocarbon DMPs with the aromatic, sulfur-bearing MDBTs to calculate maturity and generation temperatures for Type II-S oils directly from the 4-MDBT/1-MDBT ratio. Results from Type II-S Middle Eastern oils indicate the calculated MDBT temperatures have an average standard deviation of 0.7% compared to calculated C7 temperatures. Furthermore, they also have an average standard deviation of 1% compared to present-day bottom-hole temperatures (BHT). The MDBT isomers’ thermal stability between the immature to the wet gas window enables the use of this technique to assess and map fluids over a wide temperature spectrum in a basin. This stability makes these aromatic compounds especially useful in the absence of light hydrocarbons and in cases where oils have been altered by secondary processes.

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.

Determining Geothermal Resources in Three Texas Counties

This project updates the geothermal resources beneath our oil and gas fields, as part of the research for the Texas GEO project for the counties of Crockett, Jackson and Webb. Through additional bottom-hole temperatures from oil and gas wells drilled in the late 1990s to 2019, the number of sites increased from 532 to 5,410. The project improved the methodology to calculate formation temperatures from 3.5 km to 10 km, included thermal conductivity values more closely related to the actual county geological formations, and incorporated radiogenic heat production of formations and the related mapped depth to basement. The project results show deep temperatures as hotter than previously calculated, with temperatures of 150 °C possible for Webb County between depths of 2.6 – 5.1 kms, average 3.3 km; Jackson County between depths 3.0 – 5.4 kms, average 3.7 km; and Crockett County between depths of 2.7 – 8.0 kms, average 4.0 km. Based on the 150 °C temperature desired for electrical production, 677 wells or 11.6 % of them have at least this temperature or higher. The oil and gas industry can be a significant resource for unlocking our ability as a nation to extract the geothermal heat resource.

Simulation of wellbore temperature and pressure field in supercritical carbon dioxide fracturing

As unconventional oil and gas receive more and more attention, scholars pay more and more attention to waterless fracturing technology. Among them, carbon dioxide fracturing technology, as the main representative of waterless fracturing technology, has unique advantages and broad application prospects in the development of unconventional oil and gas reservoirs. However, when using carbon dioxide fracturing fluid for construction, carbon dioxide is greatly affected by temperature and pressure, so it is necessary to simulate the temperature and pressure in the wellbore during carbon dioxide fracturing construction. In this article, the basic physical properties of carbon dioxide under different temperatures and pressures are analyzed, and the changes of wellbore temperature and pressure during carbon dioxide fracturing are studied based on the generalized heat conduction theory. The results show that the faster the injection rate of CO2 fracturing fluid at the wellhead, the lower the bottom hole temperature and the higher the bottom hole pressure. However, the higher the wellhead injection temperature, the higher the bottom hole temperature, and the lower the bottom hole pressure.

Numerical simulation of flow and heat transfer performance during supercritical water injection in vertical wellbore: A parameter sensitivity analysis

Supercritical water injection is a promising technology for heavy oil thermal recovery. Predicting and regulating the thermophysical parameters of supercritical water at bottomhole are the prerequisite for achieving high recovery efficiency. In this paper, a novel numerical model was proposed to simulate wellbore flow and heat transfer of supercritical water injection. A modified correlation of frictional coefficient was developed to calculate water flow resistance near its critical point, where its properties change abruptly. The unsteady heat loss to the formation was calculated directly by solving two-dimensional unsteady heat conduction equations. They were respectively coupled in momentum and energy balance equations using an iterative scheme. This model was proved to be accurate by two oilfield cases in which the relative errors of wellbore fluid pressure and temperature are less than 1%. Then parameters sensitivity analysis of the injection pressure, temperature, mass flux and the apparent heat conductivity of insulating tube was conducted. The results indicated that the temperature variation of wellbore fluid depended on both enthalpy drop (or heat loss) and Joule-Thomson effect. An abnormal phenomenon that the fluid temperature increased with wellbore depth near the critical and pseudo-critical points was found because of the sudden increase in high heat capacity and Joule-Thomson coefficient of water. Raising the bottomhole fluid temperature was the key to enhanced oil recovery by supercritical water injection. Low apparent heat conductivity of insulating tube contributed richly to raise bottomhole fluid temperature by enlarging thermal resistance and reducing wellbore heat loss. There existed an optimal mass flux for maximizing bottomhole temperature, because when the mass flux increased, the shortened resident time within wellbore and the decreased fluid pressure favored temperature increase and decrease respectively. Selecting an injection pressure near the critical or pseudo-critical point and raising the injection temperature would increase the bottomhole temperature and reduce relative fluid heat loss.

Athabasca Toe-to-Heel Air Injection Pilot: Evaluation of the Spontaneous Ignition Based on Apparent Atomic Hydrogen-Carbon Ratio Variation

Summary An in-depth analysis was performed to determine the ignition delay via the enhanced spontaneous ignition (ESI) method on three well pairs (each pair constituted by one vertical injector and one horizontal producer) belonging to the Toe-To-Heel Air Injection (THAI) pilot in Athabasca. ESI consisted of preheating of the surroundings of injection wells by injecting a steam slug for 3 to 4 months just before starting air injection. At first, the ignition delay had been determined based on both the oil production and on the bottomhole temperatures (BHTs) recorded in the observation wells as well as at the toe of the horizontal producer. For the purposes of this paper, a more rigorous evaluation was carried out based on the variation in time of the apparent atomic hydrogen-carbon ratio (AAHCR) calculated from detailed gas analyses for a long period of time. AAHCR is a very strong synthetic parameter giving a direct indication of the peak temperature value before, during, and after the in-situ combustion (ISC) front is generated. Therefore, it provides complete information on the occurrence of high-temperature oxidation and low-temperature oxidation (LTO) reactions. Using the variation of the AAHCR, it was found that the ignition time was shorter than those determined by the previously mentioned methods. In the case of first well pair, ignition took 3 weeks as compared to the 1 month determined by the previous methods. The second well pair ignited in 1 month as compared to the previously calculated 2 months, and for the third well pair, ignition time was approximately 2 months in both cases. As an additional and complementary approach, estimation of the ignition time was also based on the variation of individual components of the produced gas. This allowed for the discovery of a new method for ignition time determination. This was possible in the THAI process, unlike conventional ISC processes, significant concentrations of hydrogen (H2) are produced, and the interpretation of its variation can give an indication of the ignition time. The new method is very simple to use, as the percentage of hydrogen in the produced gas starts to take off only after the full establishment of an ISC front, as hydrogen production is associated with high-temperature bond scission reactions in the ISC front. In general, the ignition delay is overestimated to some degree when using this method.

Subsurface geology and geochemical evaluation of the Middle Jurassic-Lower Cretaceous organic-rich intervals, West Kalabsha area, Western Desert, Egypt

The West Kalabsha (WKAL) area is a western extreme exploratory area of the Faghur Basin in the Western Desert of Egypt. The study of four wells (WKAL; A-1 X, K-1 X, P-1X, and C-1 X), interpreted with twenty seismic lines, shows that the area is dissected by a series of normal faults with an irregular, E–W strike direction. The general trend of the throw is toward the south–southeast. The most prospective area for hydrocarbon (HC) migration is toward the north (upthrown side) of an E-W striking normal fault north of the WKAl-K-1 X and A-1 X wells. The WKAL-P-1 X and WKAL-K-1 X wells in the Faghur Basin were selected for both geochemical evaluation of possible source rock intervals and burial history modelling within the basin. Integration of the wire-line logs with geochemical analysis identified six organic matter-rich intervals (OMRIs) within the Middle Jurassic-Lower Cretaceous sequence. Four intervals are in the Alam El-Bueib-3C (AEB-3C) member with a cumulative vertical thickness of 530ft. The other OMRIs are 110ft in thickness recorded within the AEB-6 (10ft) and Upper Safa (100ft) members. The studied organic matter (OM) reveals type III, IIIC, and IV kerogens (mainly gas-prone) with a terrestrial origin. They have reached a maturity level consistent with the late oil window. The expulsion threshold depth detected in the WKAL-P-1 X well is 12000ft in the AEB-3C member, whereas the active source depth limit (ASDL) is 15000ft in the Safa Member. The present study suggests a paleo-geothermal gradient range between 1.13oF/100ft and 1.39oF/100ft with an estimated regional erosion of 5500 to 7000ft of strata mainly between the Paleozoic-Jurassic and Cretaceous-Tertiary boundaries. The present-day geothermal gradient based on bottom-hole temperatures shows a geothermal gradient of 1.4oF/100ft (WKAL-P-1 X), that increases to the north to 1.65oF/100ft (WKAL-K-1 X). Burial history modelling reveals that sedimentary strata entered the mature oil zone in the Early Cretaceous (110–115Ma) at depths of 7500–8000ft in the deepest part of WKAL-P-1 X and WKAL-K-1 X wells (Paleozoic strata). Maturation continued to present, resulting in Jurassic and Lower Cretaceous strata currently falling into the late oil window.

Assessing the effect of gas temperature on gas well performance

Gas temperature is an essential parameter in estimating production rate and pressure model inside the production tubing. Three heat transfer mechanisms named as conduction, convection and radiation have been applied to identify the gas temperature declination. Gas wells with bottom hole temperature greater than 160oC and gas rates reaching 55 million standard ft3 per day (MMscf/d) indicate a higher heat loss due to convection than the other two mechanisms. Conduction is the main factor in explaining heat diffusion to the surrounding at the top of the well. The study presents a strong similarity in value compared to the field data by combining Gray correlation and heat transfer model to predict the bottom hole pressure with an error of approximately 3%. Additionally, the gas temperature affects gas rate prediction through gas viscosity and Z factor. With the gas composition mostly containing C1 (70.5%), gas viscosity and Z coefficient at the wellhead are not as high as 0.017 cp and 0.92 respectively. It is possible to have a two-phase flow, then a temperature model along the production tubing is necessary to ensure the gas production rate.

Study of the applicability of foam for steam conformance control to conditions of the Karazhanbas field

Thermal enhanced oil recovery methods are a traditional approach in the primary and secondary development of heavy oil fields. Despite the effectiveness of such methods, there are breakthroughs of working fluid into production wells due to the presence of high permeability channels, resulting in a sharp increase in the watercut and an increase in the bottom hole temperature.&#x0D; The article presents a literature review of the world experience in application of various steam conformance control methods. Based on the literature review, the applicability of foam systems at the Karazhanbas field was studied; core flood experiments were carried out to determine resistance factor and displacement efficiency. Obtained results confirm the formation of foam in reservoir conditions by increase in injection resistance during its filtration through core sample and visually at the outlet, the increase in displacement efficiency was 17,41%. The scientific novelty of the work lies in the study of the applicability of steam conformance control technology based on foam, which has not been previously studied and tested at any field in Kazakhstan.

Machine learning prediction of bottomhole flowing pressure as a time series in the volve field

Bottomhole flowing pressure (BHFP) is a critical parameter in analyzing oil and gas well performance, production forecasting and reservoir management. This study is focused on obtaining feature combinations towards low-error prediction of time-series BHFP in two wells in the Volve field. Three machine learning (ML) models (support vector regression (SVR), a distance-based model; random forest (RF), a tree-based ensemble model and Long Short-Term Memory (LSTM), a type of recurrent neural network) are used for BHFP prediction in two wells of the Volve field. The data for each well was split such that the first 70% is used in training the model, the next 15% as validation data for selecting the optimal hyperparameters and the last 15% for testing the models. The train and validation sets were used to train the models before making predictions on the test sets. While the SVR and RF models reasonably predicted the BHFP in both wells with a maximum Mean Absolute Percentage Error (MAPE) of 5.0% and 4.3% respectively, the LSTM model performed best across both wells with the MAPE less than 2.9% in both wells. ML model performance was superior for the well with the data distributed more uniformly. The three feature combinations with superior ML model performance for BHFP prediction all have five features in common namely: bottomhole temperature, oil flow rate, gas flow rate, choke size, onstream hours. The workflow in this work can be adopted for fieldwide BHFP prediction.

Evaluating geothermal energy production from suspended oil and gas wells by using data mining

Can suspended oil and gas wells be retrofitted to generate geothermal power? This study answers this question by evaluating and indexing the geothermal potential of suspended wells completed in Western Canadian Sedimentary Basin (WCSB) and identifying the best candidates for repurposing.First, a contour map of temperature gradient (TG) distribution in WCSB is developed by utilizing temperature-log data. Second, the Ordinary Kriging geostatistical technique is applied to interpolate TG at each suspended well to verify the reported bottomhole temperature (BHT). Then, a supervised fuzzy clustering (SFC) algorithm is developed to estimate the geothermal potential of each suspended well. Finally, the geothermal power and production temperature delivered to the nearest residential areas and power grids are estimated while considering heat loss in wellbore and surface pipelines.The results show that: 1) a coaxial borehole heat exchanger with 7” diameter installed in a suspended well with BHT ≥ 85 °C at depth ≤ 3,000 m can deliver up to 130 KW of geothermal power at production temperature of 50 °C to a residential area 1 km away; 2) 50% of the heating power needed in some residential areas can be gained by retrofitting suspended wells; and 3) suspended gas wells have a relatively high potential for repurposing.

Numerical simulation of THMC coupling temperature prediction for fractured horizontal wells in shale oil reservoir

In order to study the effects of different parameters in hydraulic fracturing on formation temperature after low-temperature fracturing fluid is injected into high-temperature reservoir, in this paper, considering (1) osmotic pressure and capillary pressure (2) microthermal effect (heat conduction, heat convection, heat expansion, viscous dissipation) (3) the coupling processes of temperature (T), hydraulic, (H) mechanical (M) and chemical (C) in hydraulic fracturing process, and the coupled temperature prediction model of oil-water two-phase THMC based on discrete fractures is established. The effects of fracturing fluid temperature, reservoir temperature, dimensionless conductivity, Young's modulus, injection rate, cluster spacing, and proportion of branch fracture area on reservoir and fracture temperature during the pumping and shut-in stages of shale oil reservoir were studied. The results show (1) For formations with different reservoir temperatures, the temperature drop at the fracture was approximately 97% from the start of the operation to the end of the 30-day shut-in. The saturation change caused by fracturing fluid filtration is much larger than the temperature change caused by heat transfer, and it is found that the temperature and saturation change mainly occur in the early shut-in period (2) Imbibition accelerates the filtration loss of fracturing fluid. During pumping, the bottom hole temperature with imbibition considered is lower than that without imbibition considered. The temperature curve with imbibition considered begins to deviate about 10 min after pumping, but the final temperature tends to be the same, (3) When the fracturing fluid is pumped at high pressure, the fracture and matrix will be deformed, which will improve the porosity and permeability of the near well zone, thus speeding up the heat transfer rate. The high Young's modulus inhibits the increase of permeability. Compared with the young's modulus of 40 GPa and 20 GPa, the increase of permeability decreases by 9% (4) When the well was shut in for 30 days, the cluster spacing was greater than 20 m, and the temperature change around the fracture did not affect the clusters on both sides. The spacing between the clusters was 5 m, and the perforation clusters on both sides had a significant effect on the temperature. The temperature of the reservoir between the two adjacent clusters dropped from 393 K to 385 K. When there is a branch fracture, the small cluster spacing is equivalent to increasing the complexity of the fracture and accelerating the initial heat transfer rate. (5) High injection temperature, high dimensionless conductivity, low Young's modulus and low pumping rate are conducive to the heat transfer of fracturing fluid in the formation.

A Chemical Design Example of Hydraulic Fracturing Fluids in High-Temperature Hydrocarbon Reservoirs: Case Study

Production optimization problem in hydrocarbon reservoirs has garnered prime importance in the last few years. There are numerous methods to achieve the requisite and desired production rates. One such method is hydraulic fracturing, which has been used since the 1940s. Like many other technologies, hydraulic fracturing considers the usage of various chemicals for formulating the fracturing fluid. It has a concomitant challenge of optimal selection of such fluid as per the given conditions. The objective of this study was to validate the composition of hydraulic fracturing fluid for fracturing jobs in high-temperature Jurassic oil and gas reservoirs located in Western Kazakhstan.&#x0D; A series of laboratory tests were conducted to select suitable chemicals on a scientific and practical basis. Methods used were fluid thermal stability tests, shear test and stability test - all executed on Chandler 5550 rotational viscometer. Several other tests such as emulsion break test, water analysis, crosslinking time, pH measurement and gel tests were also performed. Herein, justifications from known sources are provided alongside the enumerated laboratory tests. Thus, gelling agents, crosslinkers, breakers and various additives such as demulsifiers, pH buffers, clay inhibitors and biocides were selected. Each component has its own chemical equivalent with the desired concentration.&#x0D; The formulated hydraulic fracturing fluid was successfully implemented in 20-ton hydraulic fracturing job in the Jurassic sandstone deposits with bottom-hole temperature up to 105 ℃ and a permeability about 3 mD. The operation was successful and resulted in production increase and promising long-lasting effects.&#x0D; HIGHLIGHTS&#x0D; &#x0D; One of the common problem in hydraulic fracturing jobs is a proper fracturing fluid design in compliance with well and formation conditions&#x0D; Series of lab testing such as fluid thermal stability tests, shear test and stability test, emulsion break test, water analysis, crosslinking time, pH measurement and gel tests were performed for the proposed fracturing fluid composition&#x0D; The optimal formulation of the hydraulic fracturing fluid was selected for operations at high temperatures of the Jurassic clastic formations, in particular at 105 ℃ at depths of more than 2,000 m&#x0D; &#x0D; GRAPHICAL ABSTRACT

Coiled Tubing Program Succeeds in Harsh-Environment Tight Gas Wells

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 209032, “Successfully Adapting and Overcoming Challenges for Coiled Tubing Applications in High-Pressure Sour Environments and Horizontal Unconventional Tight Gas Wells in UAE,” by Ole Sorensen, Yang Wu, and Didier Caillon, SPE, TotalEnergies, et al. The paper has not been peer reviewed. During the completion phase of four unconventional wells in the United Arab Emirates, a detailed engineering approach overcame challenges presented by extreme conditions of pressure, temperature, and a sour environment across long horizontal sections to carry out cleanout activities successfully. This operation, the first of its kind in the country for the operator, yielded lessons for design considerations and the execution process and recommendations for coiled tubing (CT) intervention in similar working environments. It also confirmed that 110,000-psi-yield-strength quench-and-tempered (Q&amp;T) CT strings can be deployed safely in a high-pressure sour environment by implementing proper risk-mitigation strategies. Introduction The unconventional gas play (referred to as “A” in the complete paper) featured a reservoir pressure of nearly 13,000 psi and a bottomhole temperature of approximately 325°F. The environment was sour, with 5 mol% of hydrogen sulfide (H2S) and 5% carbon dioxide (CO2). The well’s architecture consisted of a 5½-in. monobore completion with cemented casing and horizontal sections ranging from 5,000 to 8,200 ft. The selected completion methodology was plug-and-perf, including up to 35 fracturing stages in a single well. Overview of CT Intervention Challenges The true vertical depth of the play was 12,600 ft on average, representing a maximum anticipated surface pressure (MASP) of 8,000 psi with the wellbore full of working fluid (8.34-lbm/gal slickwater) and a maximum potential wellhead pressure (MPWHP) of 11,300 psi with the wellbore full of gas. Also, partial pressures of H2S and CO2 exceeded 600 psi at bottomhole conditions, confirming that sour- and corrosive-service programs had to be implemented fully in this project. Convergence of MASP above 7,500 psi, CT dynamic pressure of greater than 11,000 psi, lateral length of up to 8,200 ft, and the sour and corrosive environment required a highly engineered approach on the design and selection of the CT string and configuration of the surface equipment.

Thermal behavior prediction and adaptation analysis of a reelwell drilling method for closed-loop geothermal system

The ultra-high temperature characteristic of the deep closed-loop geothermal system poses a great challenge for drilling. This paper proposes a reelwell drilling method for temperature-controlled drilling in ultra-high temperature geothermal reservoirs. Combining the flow characteristics and heat transfer mechanisms in each flow channel under three circulating modes of reelwell drilling, a set of integrated transient heat transfer models is developed for distinct thermal-associated regions. The model simultaneously couples the effect of the variable temperature-mass flow resulting from the fluid transition in different flow channels. The finite difference method is used to solve the model, and the field measurement data is employed to validate the model. The heat transfer rate and wellbore temperature distribution in reelwell drilling are investigated, and the optimum circulating mode suitable for temperature-controlled drilling is optimized. The results indicate that the cumulative bottomhole heat flux is always negative in reelwell drilling, revealing that the bottomhole temperature decreases gradually. Additionally, the absolute values of the cumulative heat flux under different circulating modes are consistent with circulating mode B > conventional drilling > circulating mode C > circulating mode A. Thus, the circulating mode B can effectively reduce the bottomhole temperature during drilling directional well. Moreover, when a suitable dual-channel valve position is selected in the middle and lower part of the wellbore and the auxiliary fluid inlet temperature is controlled to be less than 20 °C, the circulating mode B has the best temperature-controlled effect. Therefore, the circulating mode B of reelwell drilling method can provide a new option for temperature-controlled drilling for the deep closed-loop geothermal system.

Numerical analysis of heat transfer rate and wellbore temperature distribution under different circulating modes of Reel-well drilling

Reel-well drilling is a new method of ultra-deep well drilling, but the wellbore temperature distribution is not yet well understood. In this paper, considering the wellbore flow characteristics and heat transfer mechanisms under multiple flow channels and two circulating modes in Reel-well drilling, an integrated transient heat transfer model was developed for distinct thermal-associated regions based on the first law of thermodynamics. The model also coupled the variable temperature-mass flow resulting from the fluid transition in different flow channels. The model was solved using the finite difference method and validated using field measured data. The results indicate that the combined effect of heat transfer mechanism, temperature difference and flow rate difference resulted in the temperature relationship under circulating mode A satisfying: FC1 > FC3 > FC2, while that under circulating mode B showing: FC1 > FC2 > FC3. And the bottomhole temperature of the latter was eventually more than 30 °C lower than that of the former, indicating that the latter was favorable for drilling in ultra-high temperature formations. Additionally, except of the dual-channel valve position under circulating mode A, the dual-channel valve position and inlet temperature had little effect on the bottomhole temperature, not exceeding 10 °C.

Interwell connectivity inversion method of steam flooding: Based on an analytical model and genetic algorithm

The steam channeling between wells of steam flooding in heavy oil reservoirs is an important factor impacting the development effect. Interwell connectivity is a key indicator for analyzing and predicting steam channeling. At present, only the correlation between injection and production is used to analyze the interwell connectivity, and the variation characteristics of liquid production and bottom hole temperature are not comprehensively considered to achieve the quantitative prediction of interwell connectivity in steam flooding. In this paper, based on the mass-conservation equation and energy-conservation equation, the analytical-calculation model of liquid production and bottom hole temperature of steam flooding in one injection well and one production well model is established. The ‘interwell connectivity coefficients’ are used as the splitting parameter of injected steam to each production well, and the analytical-calculation model of multiwell injection-production is extended. Taking the minimum mean square deviation of the error between the liquid production and bottom hole temperature as the objective function, the genetic algorithm is used to fit the liquid production and bottom hole temperature, and the ‘interwell connectivity coefficients’ of steam flooding are inverted. The innovation of this method lies in the establishment of analytical models of multiwell injection-production fluid production and bottom hole temperature and the establishment of a variable weight function in the objective function, which improves the accuracy of interwell connectivity inversion of steam flooding. Utilizing reservoir numerical simulation technology, the accuracy of the method is verified by synthetic models of homogeneous and high-permeability channels. The method is applied to the steam flooding reservoir of the Ng5 unit in Zhongerbei, Shengli Oilfield, China. The interwell connectivity of the two steam flooding well groups is inverted, and the results are consistent with the tracer analysis results. The findings of this study can help for better understanding of the geological conditions of the steam flooding reservoirs, and provide guidance for the selection of the next development plan.