Bottom-hole Temperature Research Articles

Geothermal Gradients in the Upper Amazon Basin derived from BHT data

The Upper Amazon Basin (UAB), present foredeep of the sub Andean retro-foreland basin. It comprises Putumayo area (southeastern part of Colombia), Oriente area (eastern Ecuador) and Marañón area (northeastern part of Peru). Bottom Hole Temperature (BHT) from a regional well log database (1076 wells and 2957 logs) were analyzed and data discriminated according to drilling operations (i.e., log acquisition operations, cementing, formation test, tools misreading values), topography and shallow subsurface weathering conditions (i.e., temperature data from wells with depths below 305 m. were avoided). A new normalized database has been setup (1021 wells and 1399 logs). Analysis of this data set has allowed better understanding of the regional distribution of geothermal gradient variations within the study area. The results indicate mean uncorrected geothermal gradient (UCGG) for the UAB of 20.4 °C/km. The UCGG is a first approach based on well data with sufficient information and is useful for comparison purposes with other basin where corrected data is limited. In addition, a new computer-generated contour Geothermal Gradient Map (GGM) has been created, using 56 locations (for which number of BHT at different depths ≥ 3, and temperatures in the range 23.4 to 44.4 °C). As for the locations 2 are in Colombia, 28 in Ecuador and 26 in Peru. This map is useful in analysis data of UCGG due to its wide distribution along the basin. Finally, correction based on Horner´s method was applied to these datasets (where number of BHT ≥3 at the same depth; time since circulation - TSC incremental), obtaining a Corrected Geothermal Gradient (HCGG) of 22.9 °C/km (46 wells and 153 logs). We recommend the use of this gradient for comparative reference purposes.

Effects of Near-Surface Air Temperature on Sub-Surface Geothermal Gradient and Heat Flow in Bornu-Chad Basin, Nigeria

A study of the effect of near-surface temperature on fields of subsurface geothermal gradient and heat flow has been carried out in the Bornu-Chad Basin, Nigeria, using corrected Bottom-Hole Temperatures (BHTc) lithologic-log data from 9 oil wells. The geothermal gradient using only BHTs ranges from 15.9oCkm-1 to 38.2oCkm-1 with an average of 26.9+/-3.5oCkm-1, while that computed with mean annual temperature and BHTs ranges from 28.2oCkm-1 to 51.5oCkm-1with an average of 37.5+/-2.5oCkm-1. The geothermal gradient using the mean annual temperature and BHTs in the Bornu-Chad is higher than using only BHTs by 7.0oCkm-1. Heatflow ranges from a minimum of 61 mWm-2 to a maximum of 114mWm-2 with an average of 68+/-5.89mWm-2. The isotherm maps exhibit an increasing SW-NE trend. An average heat flow of 68+/-5.9mWm-2 deduced from Bornu-Chad basin is normal for a continental passive margin with age of about 100My. Geothermal gradient results show a distinct and direct relationship with near-surface conditions. There are indications that surface heat flow is controlled by lithology, geothermal gradient and near-surface solar radiation conditions in the Bornu-Chad basin. Consequently, it is recommended that the mean surface temperature be used in geothermal gradients and heatflows estimations. The knowledge of geothermal properties is very important in the search for geothermal energy in the area of study.

Temperature modeling for wellbore circulation and shut-in with application in vertical geothermal wells

This paper presents the development and application of a numerical model to predict the temperature distribution of the vertical borehole system during circulation and shut-in conditions. The presented model can simulate the transient temperature disturbances of the drilling fluids, the drill string, the casing strings, the cement behind the casing, and also the surrounding rock formation. The transient temperature profiles resulting from the presented model are compared with a CFD (Computational Fluid Dynamics) model using ANSYS-FLUENT. A good agreement between the results of both models is found. However, the developed model has a great advantage over the CFD model in terms of computation time and power. In addition, a comparison with field results showed a good agreement between the simulated temperature and the experimental data using the presented model. Moreover, a sensitivity analysis on the influence of the size and length of the bottom hole assembly (BHA) on the temperature of the borehole is performed. The analysis is performed for both static and dynamic conditions. The results showed a significant influence of the BHA size on the static and dynamic bottom hole temperature. However, the length of the BHA only affects the dynamic bottom hole temperature. • We present a transient numerical model for wellbore system temperature simulation. • Prediction of wellbore temperature during flowing and shut-in conditions. • Feasible for complex wellbore with multi-casing and drill-string sizes. • Application and comparison with field temperature log data. • Effect of the BHA design on the bottom hole temperature.

Research and development of ultra-high temperature delayed crosslinking acid system

The average burial depth of carbonate reservoirs in Shunbei area exceeds 7300 meters, and the bottom hole temperature is as high as 160°C. The commonly used cross-linked acid system cannot meet the needs of acid fracturing. Therefore, this article uses AM, AMPS, acrylamide (AM) modified monomers, acrylic acid (AA) modified monomers to synthesize thickener SBCH-1, the organic zirconium crosslinking agent SBJL1 was synthesized with zirconium oxychloride, isopropanol, citric acid and diethanolamine. And other auxiliary agents are selected, and the final formula is determined as: 220% HCl+0.8% SBCH-1 thickener +0.8% SBJL-lcrosslinking agent +0.8% SBYC-1 crosslinking retarder +2% SBHS-1A high temperature corrosion inhibitor +2% SBHS-1B high temperature corrosion inhibitor +1% SBTW-4 iron ion stabilizer +1% SBZP-2 drainage aid +1% SBPR-1 demulsifier. The viscosity of the system stabilized above 200mPa⋅s after continuous shearing at 160°C, 170s-1 for 30min.

An analytic model for computing the countercurrent flow of heat in tubing and annulus system and its application: Jet pump

Shale fields are currently over-reliant on electric submersible pumps (ESPs) in the early stage of artificial lift despite its weakness to sandy flow and often failing within the first three months. Jet pumps are reliable and cost-effective alternatives to the ESPs. Current studies on jet pumps have focused on designing parameters for maximizing performance; however, there have been very few investigations on predicting temperature profiles in the wellbore with a jet pump in use. Fluid temperature influences viscosity; hence, the production of heavy oil. Typically, the heavier the hydrocarbon, the greater is the variation in viscosity with temperature. Therefore accurate temperature prediction is essential for the efficient design of heavy oil production facilities. This paper offers an analytic model to compute temperature profiles in the tubing and annulus. Results show a good match with a field data set.Data set from a well in Tah field in China is used to validate the model. In addition, sensitivity analyses were performed that showed that injection temperature affects the annulus temperature profile, leading to significant changes in frictional pressure loss at shallow depths. In contrast, injection rate has less influence on temperature profiles, although, of course, higher fluid velocity causes greater frictional losses. Results show that a hotter and relatively small flow rate leads to lesser pumping cost by reducing frictional pressure drop during the operation.The proposed model ideally requires the bottom-hole temperature as a boundary condition (BC). When subsurface temperature data are unavailable, as often the case due to cost, a computing method is offered in the paper for reliable temperature profile estimation from only two data points at the wellhead.

A Game Changer in Scale-Squeeze Technology

Background Field trials using a new scale-inhibitor technology that improves treatment lifetime of scale squeezes have been successfully performed in the Gulf of Mexico. Tomson Technologies, in partnership with Shell, developed proprietary nanoparticle carriers that enhance scale-inhibitor adsorption to the reservoir and control the return rate for extended periods of time. This technology results in less chemical bleed off in the initial flowback and increases the chemical retained in the reservoir, allowing for more effective squeeze treatments. Both nanoparticle-enabled phosphonate and polymer inhibitors have now been developed and successfully squeezed in the field. Phosphonate inhibitors are widely used for squeeze treatment due to their desirable adsorption and release properties in carbonate and sandstone reservoirs. Minor changes have been made to the chemistry, but overall, the fundamentals have remained unchanged for decades. Polymeric scale inhibitors have also been developed for cases in which phosphonates are not applicable. The nano-enhanced technology provides a large improvement of treatment lifetime of 2 to 4 times (200-400%) when compared to incumbents, making this technology advancement attractive even in cases where current squeezes are considered successful. The well selected for this case study is an offshore formation with a predominantly sandstone mineralogy (approximately 80% quartz) with 25-30% porosity and bottomhole temperature of 183°F (83°C). Technology From the Lab to Field A sandpack sample from the trial well was used in the laboratory to deter-mine the adsorption and desorption properties of the nano-enabled inhibitor in realistic rock conditions. Multiple conditioning steps were used before product was injected in a sequence that mimicked field squeeze treatments. Mass-balance results from the sandpack experiment show adsorption of approximately 8 mg of polymer retained per gram of crushed reservoir rock used in the experiment. A typical rule of thumb for phosphonate-scale inhibitors (only as a comparison since this is a polymeric scale inhibitor) is 1-2 mg of inhibitor retained per gram of rock. Therefore, this is considered a large improvement on adsorption. There are challenges associated with measuring polymers in brine as residuals; however, multiple methods, both in-house and external, were com-pared to ensure accuracy. The results using the nano-enhanced scale inhibitor show concentrations higher than 1 mg/L of active polymer for over 7,000 pore volume of return in the sandpack experiment. Complete intact core experiments were also conducted with reservoir fluids and showed no formation damage during the injection of the product with regained oil permeability of 96%. Oil permeability was in the 150-200 mD range for the intact core experiments. Third-party coreflood testing was performed with nitrified and foamed stages to ensure compatibility with the nano-enabled chemistry. No formation damage was observed with the nitrification of the stages containing the nano-enabled chemistry. Field Application Case Study After extensive lab validation of the product and supporting corefloods to de-risk the technology, Well A was selected by Shell to be the first well treated with the new nano-enabled extended-lifetime inhibitor.

Source rock maturity evaluation and its implications for regional petroleum charge, Sirt Basin, Libya: Insights from regional geochemical assessments and modelling study

Six marine and lacustrine source rocks were studied to define their thermal maturation levels in the largest, youngest, and most productive petroliferous sedimentary basin in Libya (Sirt Basin). From the oldest to the youngest, the studied source rock formations were: 1) Middle Nubian; 2) Etel; 3) Rachmat; 4) Sirte; 5) Kalash; and 6) Hagfa. The calibrated basin modelling studies (1D, 2D, and 3D) were used to generate regional maturation maps for each source rock in the basin. Thermal maturity calibration was carried out at different levels utilising measured and simulated vitrinite reflectance (VRo), pyrolysis Tmax data, and 39 typical wells for burial history modelling and geochemical screening. Corrected bottom hole temperature data were used to obtain the geothermal gradient and heat flow throughout the basin. The thermal gradient and heat flow analyses results indicated that the Sirt Basin has an average geothermal gradient of approximately 1.58 °F/100 ft and an average heat flow of 72 m.W.m−2 with a systematic heat flow increase toward the basin platforms and a decrease toward the basin troughs. The conducted assessments in the Sirt Basin presented different levels of source rocks thermal maturity due to variable burial depths, with an average VRo range of 0.35%–2%. The lower Cretaceous source rocks were subjected to higher degrees of diagenesis of organic matter (i.e. mid-to over-mature rocks), with an average VRo of 0.9%–2%. In contrast, the Upper Cretaceous source rocks demonstrated a wide range of thermal maturity (from marginally to late mature) in the deepest part of the Sirt Basin (Ajdabiya trough), whereas the late Palaeocene source rocks entered the mid-to late-maturity levels in the Wadayet trough (North Ajdabiya trough).

Numerical simulation of foam diversion acidizing in heterogeneous reservoirs

Abstract Foam diversion acidizing can effectively solve the problem of acid distribution with severe heterogeneity between and within layers. Based on the foam diversion principle, the gas trap theory, and volume conservation principle, the foam slug diversion acidizing model was established and solved considering the change of bottomhole temperature and deviation factor of foam. The simulation results show that the change of temperature has a great influence on the diversion effect at the initial stage of injection, but a small influence at the middle and late stage. The effect of temperature on the highly permeable layer is greater than that of temperature on the low permeability layer. The deviation factor of foam is mainly controlled by temperature at the initial stage, and by pressure at the middle and late stage, and the whole process shows a downward trend, which has little influence on the diversion effect. The quasi-skin factor of gas trap is the most important parameter that influences the effect of foam diversion. The water saturation of the low permeability layer rises faster than that of the high permeability layer, and the effect of diversion is obvious. The research results have a strong guiding significance for foam diversion acidizing.

Geothermal Assessment of Target Formations Using Recorded Temperature Measurements for the Alberta No. 1 Geothermal Project

The Alberta No. 1 project is a planned power and heat (direct use) geothermal project located within the County of Grande Prairie and Municipal District of Greenview. For the project to successfully produce power and heat on a commercial scale, temperatures of 120 °C are desirable. The produced fluids must also be from highly permeable formations from depths of less than 4500 m. Bottomhole temperature measurements and wireline logs from Alberta’s extensive oil and gas database were used to determine the depths to target formations and temperatures within these formations in the project area. The target formations include the dolomitized carbonate units of Devonian age from the Beaverhill Lake Group to the top of the Precambrian Basement. Permeable Devonian-aged sandstone units such as the Granite Wash Formation are also targets. Results suggest that elevation to the top of the Beaverhill Lake Group range from 3104 m to 4094 m and temperatures at the top of the formation range from 87 °C to 123 °C in the study area. Elevation to the top of the Precambrian Basement ranges from 3205 m to 4223 m and temperatures at the formation top range from 74 °C to 124 °C. Within the area where Alberta No. 1 plans to drill, temperatures close to and exceeding 120 °C are expected within the target formations.

Interpretation of Bottom Hole Temperature Data from CO2 Injection Projects

A new approach is presented for analyzing bottom hole temperature (BHT) data from CO2 injection projects. The basic premise of the methodology is: (a) during injection, both bottom hole pressure (BHP) and BHT approach quasi-stabilized values, and (b) the ratio of these changes (from ambient conditions) is the same as the ratio of slopes from transient Horner analysis of temperature and pressure data from the subsequent warmback/falloff periods. Once the slope of the pressure Horner plot is estimated from a steady-state temperature-pressure change cross plot and the slope of a temperature Horner plot, the formation permeability can be readily determined. This provides an independent estimate of formation permeability without utilizing transient pressure data.

Monitoring Migration of Injected CO2 at a Northern Niagaran Pinnacle Reef Via Distributed Temperature Sensing (DTS) and Behind-Casing Sensors

Conventional reservoir monitoring techniques in Carbon Capture & Storage (CCS) and CO2-Enhanced Oil Recovery (EOR) sites include surface and bottomhole pressure and temperature monitoring at injection and monitoring wells, along with flow rate measurements of injected CO2. In this paper, novel monitoring techniques involving a realtime distributed temperature sensing (DTS) system and multi-depth behind-casing pressure and temperature sensors are evaluated at a CO2-EOR reef in the Northern Niagaran Pinnacle Reef Trend (NNPRT). Data from these monitoring technologies are evaluated for the purpose of monitoring bottomhole conditions in response to injection of CO2 at a nearby injection well and monitoring migration of injected CO2 within the storage formation after the monitoring well was converted to an injection well.

Ultra-High Temperature Drilling Fluid Technology for Drilling Well Jiantan-1

The well Jiantan-1 is a key exploratory well of PetroChina located in the Jianshan structure of the central rhinoplasty belt in the Chaidamu Basin. The main purpose of this 6343 m well is to explore the gas reserves in the base rocks of the Jianshan structure. The highest bottom hole temperature measured is 235℃, one of the highest bottom hole temperatures encountered in onshore drilling. The formations drilled in this area have fractures that are fully developed, long sections of gypsum and mudstones, high pressure saltwater zones, high CO2 concentrations and high geothermal gradient. Borehole wall collapse, mud losses, overflow, creeping and tight hole in the gypsum/mudstone formations are downhole troubles encountered and sometime intertwined with each other during drilling. To deal with these problems, laboratory study was conducted on several aspects of the drilling fluid used, which are high temperature stability, rheology and high temperature filtration control. An organic salt drilling fluid was formulated with additives specially selected, such as ultra-high-temperature filter loss reducers, anti-collapse additives with plugging capacity, lubricants and thermal stabilizers etc. This drilling fluid is able to resist high temperatures up to 240℃. After aging for 72 hours, the HTHP filtration rate was maintained with 10 mL, the coefficient of friction was less than 0.1, and the invasion depth on a sand-bed less than 12 cm. In addition, the fourth and fifth intervals of the well penetrated formations with micro-fissures and a basal rock weathered crust, and mud losses occurred many times into the fissures. A lost circulation material slurry for the well Jiantan-1 was then developed with choice rigid, flexible and gel-like plugging additives which are suitable for use at elevated temperatures. Using this mud loss control slurry, the pressure bearing capacity of the formations into which mud losses have occurred was finally enhanced. The organic salt drilling fluid and the mud loss control slurry played a major role in preventing and controlling borehole wall collapse and mud losses, ensuring the success of the drilling of the first ultra-high temperature Jiantan-1 well in Chaidamu Basin.

Equipment and Methods of Measuring High Temperature Rheology of Drilling Fluids

Since the six-speed direct reading viscometer is unable to measure the change of mud rheology with downhole temperature, downhole pressure, downhole shear rate and time, drilling fluid researchers turn to the high temperature high pressure (HTHP) rheometer for evaluating the rheology and thermal stability of drilling fluids, hoping that it will give more scientific and effective test results. To simulate the actual mud properties downhole, several test methods are established, which are test of low shear rate viscosity, test of loss of viscosity at high temperatures and test of changes of mud viscosity with time at dynamic and static conditions. These tests are used to characterize the cuttings carrying capacity, rheology at elevated temperatures and high temperature stability of drilling fluids at dynamic and static conditions, the test results can reveal the actual rheology of the drilling fluids downhole. Field application of the HTHP rheometer in testing the properties of the organic salt drilling fluid used in drilling the well Chengtan-1 indicated that the test method can be used to provide field engineers with accurate data for judging whether the mud properties can meet the requirements of drilling operation under high bottomhole temperatures. The test method and the HTHP rheometer have provided a scientific and reliable way of designing, developing and using high temperature drilling fluids and mud additives, and greatly made up for the shortcomings and defects of using the six-speed viscometer to measure the rheology of drilling fluids.

Real-Time Prediction of Equivalent Circulation Density for Horizontal Wells Using Intelligent Machines.

Equivalent circulation density (ECD) is an important part of drilling fluid calculations. Analytical equations based on the conservation of mass and momentum are used to determine the ECD at various depths in the wellbore. However, these equations do not incorporate important factors that have a direct impact on the ECD, such as bottom-hole temperature, pipe rotation and eccentricity, and wellbore roughness. This work introduced different intelligent machines that could provide a real-time accurate estimation of the ECD for horizontal wells, namely, the support vector machine (SVM), random forests (RF), and a functional network (FN). Also, this study sheds light on how principal component analysis (PCA) can be used to reduce the dimensionality of a data set without loss of any important information. Actual field data of Well-1, including drilling surface parameters and ECD measurements, were collected from a 5–7/8 in. horizontal section to develop the models. The performance of the models was assessed in terms of root-mean-square error (RMSE) and coefficient of determination (R2). Then, the best model was validated using unseen data points of 1152 collected from Well-2. The results showed that the RF model outperformed the FN and SVM in predicting the ECD with an RMSE of 0.23 and R2 of 0.99 in the training set and with an RMSE of 0.42 and R2 of 0.99 in the testing set. Furthermore, the RF predicted the ECD in Well-2 with an RMSE of 0.35 and R2 of 0.95. The developed models will help the drilling crew to have a comprehensive view of the ECD while drilling high-pressure high-temperature wells and detect downhole operational issues such as poor hole cleaning, kicks, and formation losses in a timely manner. Furthermore, it will promote safer operation and improve the crew response time limit to prevent undesired events.

A Multivariate Long Short-Term Memory Neural Network for Coalbed Methane Production Forecasting

Owing to the importance of coalbed methane (CBM) as a source of energy, it is necessary to predict its future production. However, the production process of CBM is the result of the interaction of many factors, making it difficult to perform accurate simulations through mathematical models. We must therefore rely on the historical data of CBM production to understand its inherent features and predict its future performance. The objective of this paper is to establish a deep learning prediction method for coalbed methane production without considering complex geological factors. In this paper, we propose a multivariate long short-term memory neural network (M-LSTM NN) model to predict CBM production. We tested the performance of this model using the production data of CBM wells in the Panhe Demonstration Area in the Qinshui Basin of China. The production of different CBM wells has similar characteristics in time. We can use the symmetric similarity of the data to transfer the model to the production forecasting of different CBM wells. Our results demonstrate that the M-LSTM NN model, utilizing the historical yield data of CBM as well as other auxiliary information such as casing pressures, water production levels, and bottom hole temperatures (including the highest and lowest temperatures), can predict CBM production successfully while obtaining a mean absolute percentage error (MAPE) of 0.91%. This is an improvement when compared with the traditional LSTM NN model, which has an MAPE of 1.14%. In addition to this, we conducted multi-step predictions at a daily and monthly scale and obtained similar results. It should be noted that with an increase in time lag, the prediction performance became less accurate. At the daily level, the MAPE value increased from 0.24% to 2.09% over 10 successive days. The predictions on the monthly scale also saw an increase in the MAPE value from 2.68% to 5.95% over three months. This tendency suggests that long-term forecasts are more difficult than short-term ones, and more historical data are required to produce more accurate results.

Parametric Study of Mechanical Stresses within Cement Sheath in Geothermal Wells

A cement sheath, placed between the casing and the formation, is an important barrier that establishes a hydraulic seal and provides zonal isolation, preventing fluid communication in the wellbore. In geothermal wells, stress induced by high bottom-hole temperature is one of the major factors triggering failure in the cement sheath. However, the influence of heat flow direction and differential temperature, relative to other design and operating factors, is not well understood. The objective of this paper is to investigate these two important factors.In this study, an analytically verified 2D numerical model was used to perform a parametric study of mechanical stress within a cement sheath. Loading conditions applied to the model included maximum and minimum horizontal formation stresses, wellbore pressures, and temperature differences. Sensitivity analysis was conducted to understand the effect of cement properties, temperature difference between the casing and the formation, and casing pressure on stresses in the cement sheath. Sensitivity response curves demonstrated the relative influence of investigated parameters on radial and hoop stresses. Results showed that heat transfer from the formation to the casing (Ti < Tf) is more detrimental to cement integrity than the opposite scenario (Ti> Tf). When heat flows away from the wellbore, hoop stress in cement is mainly dependent on temperature difference, while radial stress is primarily dependent on temperature difference as well as wellbore pressure. When heat flows toward the wellbore, radial stress in cement is primarily a function of temperature difference and wellbore pressure. Hoop stress, on the other hand, is mainly dependent on temperature difference and the cement’s thermal expansion coefficient.

Integration of Well Logging and Remote Sensing Data for Detecting Potential Geothermal Sites along the Gulf of Suez, Egypt

The Gulf of Suez area is one of the most favorable regions in Egypt for geothermal exploitation since it hosts an evident cluster of superficial thermal springs. Some of these thermal springs include Hammam Musa, Hammam Faraun, Sudr, Ayn Musa and Ain Sokhna, which are characterized by high temperatures ranging between 35 °C to 86.66 °C. It is this feature that makes the Gulf of Suez locality sufficient for geothermal power production. Corrected bottom hole temperature (BHT) data from 197 oil wells situated onshore and offshore of the Gulf of Suez were utilized for the present research. The results indicated that the study area has a geothermal gradient ranging from 24.9 to 86.66 °C/km, a heat flow ranging from 31 to 127.2 m W k−1, a thermal conductivity of 2.6–3.2 W m−1 k−1, and an amplitude temperature varying from 49.48 °C to 157.8 °C. The derived geothermal and geological layers were used together with the remote sensing thermal infrared and topographic data, to map relevant physiographic variables including surface elevation, fractures density, drainage density, nighttime land surface temperature and major lithological units. The nine produced variables were integrated in GIS to model the geothermal potential map (GTP) for the Gulf of Suez region. The model identifies the northeastern and the southwestern areas as equally two sites for high geothermal potential. Findings of this study demonstrate that integration of well logging and space data with the adopted geospatial techniques is a practical method for geothermal prospecting in similarly geologic and tectonic setting in Egypt and East Africa.

Experimental studies of the removal properties of liquid and solid foaming surfactants

Using the laboratory model of a well, foaming and removal properties of liquid and solid surfactants (savenol, light and dark stinol, Sofir M2, TEAS and Nadra) are studied. The authors determine experimentally the height of the level of the foam in the glass column at the end of the foam-forming process and the duration of re-moving half volume of liquid out of the foam. Using height and duration values, the authors determine the multi-plicity and stability of the foam. Based on the results of experiments on the laboratory model of the well, a graph-ical dependence of the multiplicity and stability of the foam on the mass concentration of surfactants in fresh and salt water, in mineralized water with the addition of hydrocarbon condensate for various temperatures is con-structed. Based on the results of experimental studies, the influence of the concentration of surfactants in a foam-ing liquid, the salinity of water, hydrocarbon condensate and temperature on the foaming ability of liquid and solid surfactants for the removal of liquid from watered gas and gas condensate wells is analyzed. The authors determine the optimal values of the concentrations of foaming surfactants in aqueous solutions. Above these val-ues the multiplicity and stability of the foam varies slightly. It has been established that the outflow properties of the solid Nadra surfactant are the best in saline water and in solutions with hydrocarbon condensate, in contrast to the investigated liquid surfactants. Based on experimental studies, the patterns of foaming of aqueous surfac-tant solutions with modeling bottomhole temperature (from 20 to 80 °) are established. The authors recommend the use of various types of surfactants under different operating conditions of wells with a high fluid content in the well production. Foaming surfactants are supplied to the bottom of the well in the form of aqueous solutions and samples of solid surfactants. As a result, the foamed formation fluid brings to the surface not only the liquid phase, but also the solid particles that accumulate at the bottom due to corrosion of the pipe metal, the destruction of cement stone and rock of the bottomhole formation zone.

Interpretation of bottom-hole temperature data from CO2 injection projects

Although bottom-hole temperature (BHT) data is routinely collected with bottom-hole pressure (BHP) data during CO2 injection in geological storage projects, it is seldom analyzed in a quantitative manner. However, the BHP and BHT signals do exhibit correlated behavior. This study proposes a practical approach for using BHT data from warmback (no injection) periods, in conjunction with the amplitude of BHP and BHT changes during the preceding injection event, to estimate formation permeability. The methodology is demonstrated using data from the AEP Mountaineer project in USA where CO2 injection was carried out into a saline aquifer. Estimated permeability values from the proposed approach are in good agreement with those obtained from transient pressure analysis of BHP data from the falloff period.

Numerical Investigation on Heat Transfer Characteristics in Electronic Cavity of Downhole Measurement-While-Drilling System

Abstract In recent years, the number of deep wells and ultra-deep wells is increasing gradually, and the bottom hole temperature of many wells reaches more than 200 °C, which puts forward higher requirement for the downhole measurement-while-drilling system. In this paper, a new active cooling method is proposed to protect electronic components in the electronic cavity from high temperature. The circuit board is cooled by direct contact with the cold end of a custom split-Stirling refrigerator. According to the different heat loads, the electronic components can operate in the proper temperature range by adjusting the piston motion frequency and inflation pressure. At the same time, the electronic cavity is filled with thermal insulation material to induce heat leakage from the environment. The thermal resistance of solid insulation material, argon, and vacuum is studied, and the required effective cooling power is determined. When the thermal insulation material is vacuum, which is the best resistance medium when compared with solid insulation material and argon according to the research results, the effects of the structure size of circuit board and electronic cavity, material property and operational environment on the required effective cooling power and maximum temperature on the room temperature chamber wall of the split-Stirling refrigerator are discussed.