Bottom-hole Temperature Research Articles

Simulation and analysis of matrix stimulation by diverting acid system considering temperature field

In the acidizing process, the problem of an uneven distribution of acid owing to excessive heterogeneity of carbonate rocks is increasing. Diverting acid with intelligent diverting characteristics is a key technology used to distribute acid uniformly in heterogeneous carbonate reservoirs. The process of diverting an acid stimulation is accompanied by some complex processes, such as a reactive mass transfer, porous media heat transfer, reaction heat release, and changes in the chemical characteristics. The current evaluation model of diverting an acid stimulation in theory has not considered such factors. In addition, an experimental evaluation method is difficult to apply to simulate the formation conditions under high temperature and pressure. Therefore, in this paper, we first evaluate the rheological properties of a novel VES diverting acid, and then establish an equation of acid viscosity change under the influence of multiple factors. Finally, a multi-reservoir diverting acidizing model with comprehensive consideration of the heat transfer, mass transfer, and chemical properties was established, and the effects of diverting the acidizing under reservoir conditions was simulated and analyzed.An experimental evaluation of novel VES diverting acid shows that the growth of a secondary wormhole is longer and the dissolution morphology is more uniform than that of the main wormhole. During the process of diversion, there is an obvious protrusion in the pressure drop curve of the acid. The simulation and analysis results show the following: The simulation of acid entering into multiple layers shows that diverting the acid can effectively increase the amount of acid entering into the low permeability layer, which results in a better development of a wormhole in a low permeability layer. It also reduces the non-uniformity of the acid distribution between the layers. The effects of the bottomhole temperature on the diverting acid viscosity exceed the effect of the reaction rate and the diffusion coefficient, which results in a higher bottomhole temperature, and worse diversion effect. The injection displacement of acid has a slight effect on the diverting effect. The higher the displacement, the better the effect of diversion. The heterogeneity of a formation has a significant effect on the diverting effect, namely, the higher the heterogeneity, the weaker the effect.

Numerical study of non-isothermal flow and wellbore heat transfer characteristics in CO2 fracturing

A novel 1D+1D model for wellbore temperature and pressure prediction during CO2 fracturing is established with the consideration of CO2 property changes, pressure work and viscous dissipation. The model is verified by the field data from a CO2 injection well, analytical solution and grid independence validation. Improvement of the model is presented by a comparison with the previous work. Then a case study of CO2 fracturing is performed to analyze the influence of various treating parameters based on the novel model. The simulation results indicates that when the injection rate increases from 0.5 m3/min to 4 m3/min, the bottom-hole temperature decreases first then increases, while the wellbore friction increases by 30.14 MPa. However, the high friction drop caused by a high injection rate can be lowered by the tubing and casing injection significantly. Additionally, the time derivative of temperature is still obvious at the end of the fracturing, which makes the steady state assumption not suitable. A lower injection temperature can reduce CO2 temperature profile significantly and increase CO2 pressure profile slightly, which is beneficial for sand carrying. Increasing injection pressure can raise CO2 pressure and the temperature as well, although the pressure gradient is almost unchanged.

Deep thermal regime, temperature induced over-pressured zone and implications for hydrocarbon potential in the Ankleshwar oil field, Cambay basin, India

Ankleshwar oil field situated in the southern part of the Cambay basin, forms one of the prominent onshore Tertiary hydrocarbons bearing regions of western India. A detailed multiparametric lithological analysis of the well logs obtained from 16 deep wells, indicate conspicuous trend of inversion in density and transit time below a depth of about 1250 m, which coincides with the presence of moderately high overpressure zone within the reservoir and appear temperature induced. Estimated temperature gradient based on the corrected Bottom Hole Temperatures, recorded at different depths in the boreholes, are found to be quite high (∼53 °C/km) at deeper levels, especially in the overpressured zone, that contains low conductive Cambay shales. Estimated heat flow of 75.2 mW/m2 at Ankleshwar, together with high Moho temperatures of about 880 °C and an extremely shallow depth to subcrustal melting (∼50 km), would suggest that not only the northern part, the entire hydrocarbon bearing Cambay basin, along with the Mumbai offshore region, is anomalously warm. In view of the presence of high thermal anomaly, low conductive shales of the Cambay basin might be a good target for shale gas investigation, as the prevailing in situ temperature is one of the crucial factors in oil-to-gas cracking.

Geothermal potential of the St. Lawrence Lowlands sedimentary basin from well log analysis

The heterogeneous distribution of minerals in different rock types poses several challenges for assessing thermal conductivity, heat flow and temperature of sedimentary basins, especially when databases coming from the oil sector are the only source of information. The objective of this study was to develop a new methodology that uses well log data to better infer the thermal conductivity variations of sedimentary formations in order to evaluate heat flow and extrapolate temperature at depth. The methodology was applied to the St. Lawrence Lowlands basin, with constrains from the available oil and gas database not designed for geothermal exploration purposes. The main idea was to analyze quantitatively well log data with an inversion approach from limited reference wells and derive empirical relationships to calculate a thermal conductivity profile for each available well. Pressure and temperature corrections were then considered. These continuous logs of thermal conductivity were used to estimate the Earth’s heat flux density using bottomhole temperatures and to extrapolate temperature at depth. A modified version of Poisson’s equation was solved by the finite difference method for this purpose. The average temperature and its standard deviation obtained with this approach for the St. Lawrence Lowlands at 1000, 2500 and 5000 m depth is approximately 32 ± 6.9 °C, 63 °C ± 12.7 °C and 119 °C ± 28.3 °C, respectively. Moreover, temperature ranges from 19 to 52 °C, 41 to 112 °C and 75 to 236 °C at 1000, 2500 and 5000 m depth, respectively.

Analysis of Wellbore Temperature Distribution and Influencing Factors During Drilling Horizontal Wells

Horizontal well drilling technology is widely used in the exploitation of petroleum and natural gas, shale gas, and geothermal resources. The temperature distribution of wellbore and surrounding formation has a significant influence on safe and fast drilling. This study aims to investigate the temperature distribution of horizontal wellbores during circulation by using transient temperature model. The transient temperature prediction model was established by the energy conservation law and solved by the relaxation iterative method. The validity of the model has been verified by the field data from the Tarim Oilfield. The calculation results showed that the highest temperature of the drilling fluid inside the drill string was at the bottomhole and the highest temperature of annulus drilling fluid was at some depth away from the bottomhole. Sensitivity analysis of various factors that affect the temperature distribution of annulus drilling fluid were carried out, including the circulation time, the flow rate, the density of drilling fluid, the inlet temperature, the vertical depth, the horizontal section length, and the geothermal gradient. It can be found that the vertical depth and the geothermal gradient have a significant influence on the bottomhole temperature, and inlet temperature plays a decisive influence on the outlet temperature. These findings can supply theoretical bases for the horizontal wellbore temperature distribution during drilling.

Effect of Hydrophobic Modification on the Properties of Polymer‐Blended Microemulsion Gels

AbstractPhase behavior of sodium oleate (NaOl)/isoamyl alcohol‐based lamellar gel phase in cedar oil/water medium in the presence of the nonionic polymer hydroxyethyl cellulose (HEC) and its hydrophobic modified product (HMHEC) is investigated for the development of polymer‐embedded surfactant gels. HMHEC is more soluble in oil‐in‐water (o/w) microemulsions, but nonionic HEC shows limited solubility in the lamellar microemulsion (o/w type). Quantitative estimation of rate of adsorption of the polymer on lamellae bilayers can be easily done by Sudan solubilization and methylene blue complexation methods. Addition of HMHEC to the lamellar gel phase increases the polymer solubilization limit of lamellar gels as well as the viscoelasticity and thermal stability. The polymer‐embedded microemulsion gel acts as a “clean gel” since it exhibits good solubilization in different hydrocarbon media at ambient conditions. Elastic modulus of the polymer‐embedded gel influences directly the suspension performance of gels at high temperature and yields a reasonable sand‐settling velocity acceptable according to fracturing standards. The thermal characteristics and viscoelastic properties of polymer‐embedded gel were found to be suitable for moderate‐temperature reservoir stimulation where the bottom hole temperature is in the range 70–75 °C. Already a large amount of experimental data on pure microemulsions (without polymer) exists. Our studies indicate that the developed polymer‐embedded microemulsion gel has great potential as a model system for the study of polymer–microemulsion interactions.

Petroleum occurrences in the carbonate lithologies of the Gohta and Alta discoveries in the Barents Sea, Arctic Norway

Investigation of petroleum inclusions in carbonate samples from the Senilix well in the Barents Sea reveals petroleum entrapment in Paleozoic carbonates at reservoir temperatures from as low as 87.3°C to more than 130°C. Using corrected bottom hole temperatures, this corresponds to depths of 2800–4100 m, compared to the present-day depth of these samples of only 1965.9–2020.5 m. The oil in the Gohta and Alta discoveries is concluded to be of either Lower Triassic or Paleozoic origin based on the isomer distribution of triaromatic dimethylcholesteroids (TA-DMC). A potential source-rock candidate is the Ørret Formation, which is the time-equivalent to the Ravnefjeld Formation in Greenland. These oils are of a different origin compared to oils in the nearby Skrugard (renamed to Johan Castberg) discovery which contain oil sourced from the Upper Jurassic Hekkingen Formation. Evidence is presented to suggest that the Gohta and Alta oils represent blends of petroleum expelled at maturities ranging from about 1.0% calculated vitrinite reflectance (Rc) to more than 1.3%Rc, and this corroborates the inferences made from the petroleum inclusions. This emerging play is significant to exploration in the karst developed on the Barents Shelf and the Bjarmeland Platform during the Permo-Carboniferous. Karst reservoirs have been linked to eustatic sea-level changes, and analogous karst reservoirs may be present elsewhere in the Circum-Arctic: for example, in the Sverdrup Basin.

Expression of the Colorado Mineral Belt in Upper Cretaceous Niobrara Formation Source Rock Maturity Data from the Denver Basin

New source rock maturity data along the Colorado Mineral Belt trend in the Denver Basin reveal that source rocks in the deepest portion of the basin range from the onset of oil generation to wet gas maturity across a distance of less than 30 miles along present day structure. Additionally, sampled rock core and cuttings along a northeast-southwest transect reveal that the Niobrara Formation is within the oil maturity window all the way to the Nebraska-Colorado border. The correlation of these analyses to an identified thermal anomaly demonstrate that maturity along these trends is affected by a historical increase in heat flow that can still be seen in the present-day bottom-hole temperatures. The identified maturity anomaly has significant implications for Niobrara prospectivity within the basin. Crossplotting, mapping, and numerical modeling show the onset of hydrocarbon maturity in the Niobrara is represented by 432 °C Tmax and that hydrocarbon expulsion occurs between 438 °C and 443 °C Tmax. In the Niobrara Formation of the Denver Basin there is a strong correlation between oil and gas shows, elevated bottom-hole temperatures (and thermal gradients), and geochemical maturity parameters. Through mapping of maturity and free hydrocarbon anomalies, more than 80% of the present day production can be predicted with source rock mapping.

Geothermal Characterization of the St. Lawrence Lowlands Sedimentary Basin, Québec, Canada

Defining temperature at depth to identify geothermal resources relies on the evaluation of the Earth heat flow based on equilibrium temperature measurements as well as thermal conductivity and heat generation rate assessment. Such high-quality geothermal data can be sparse over the region of interest. This is the case of the St. Lawrence Lowlands sedimentary basin covering 20,000 km2 to the south of Quebec, Canada, and enclosing only three wells up to a depth of 500 m with equilibrium heat flow measurements. However, more than 250 oil and gas exploration wells have been drilled in this area, providing for this study (parce que c'est 93 sinon) 81 locations with bottom-hole temperature up to a depth of 4300 m, however, not at equilibrium. Analyzing these data with respect to the deep geothermal resource potential of this sedimentary basin requires evaluating the thermal conductivity and heat generation rate of its geological units to properly extrapolate temperature downward. This was done by compiling literature and recent thermal conductivity measurements in outcrop and core samples as well as new heat generation rate estimates from spectral gamma ray logs to establish a first thermal assessment of geological units deep down into the basin. The mean thermal conductivity of the thermal units varies from 2.5 to 6.3 W/m·K, with peak values in the basal sandstones, while the heat generation rate varies from 1.6 to 0.3 µW/m3, decreasing from the upper caprocks toward the base of the sequence. After correcting the bottom-hole temperatures for drilling disturbance with the Harrison correction and subsequently for paleoclimate variations, results indicate a mean geothermal gradient of 23.1 °C/km, varying from 14 to 40 °C/km. Evaluating the basin thermal state from oil and gas data is a significant challenge facilitated by an understanding of its thermal properties.

Eliminate Decision Bias in Facilities Planning

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 187283, “Eliminate Decision Bias in Facilities Planning,” by Z. Cristea, Stochastic Asset Management, and T. Cristea, Consultant, prepared for the 2017 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, 8–11 October. The paper has not been peer reviewed. The complete paper holds the traditional facilities-planning methodologies, heavily based on design-basis documents and biased toward the most-conservative conditions, fail to recognize the entirety of operational conditions throughout the oilfield life cycle, leading to significant residual risk and the wastage of resources in the operations stage. An integrated stochastic approach is proposed, accounting for both subsurface and surface uncertainties and their interrelations throughout field life. Introduction The authors discuss an unbiased, data-driven stochastic work flow addressing the effect of subsurface uncertainties on surface-facilities design and operational decisions. Unlike classical design approaches, in which the most-conservative values are typically used as design input variables and assembled into design-basis documents, the stochastic work flow accounts for design-input-variable distribution and combination throughout the entire system life cycle. An example case is provided in which a flow-assurance risk is managed and chemical consumption optimized in a wet-gas field development. Theory and Definitions Oil and gas engineering projects are typically processes of high variety, low volume, and intermittent productivity, and with a high rate of diversification and complexity. Conversely, oilfield-facilities operations are expected to be continuous, characterized by high volumes and low variety. This expectation is reflected in the approach toward facilities design, where single-point, “conservative” design conditions are proposed and assembled as facilities design-basis documents. This approach frequently fails to recognize the risks and uncertainties associated with oilfield developments. In the proposed work flow, deterministic models are established to account for the dependencies between design input variables {static variables [i.e., bottomhole pressure (BHP) and bottomhole temperature (BHT)]} and the desired objective [static results (i.e., chemical- injection rate)]. In the provided example, the analyzed variables change because of subsurface and surface events with different levels of uncertainty (i.e., condensate banking, lean-gas injection, water breakthrough). Stochastic algorithms are used to create probability-distribution functions (PDFs) for all analyzed design input variables (stochastic variables). Stochastic algorithms are then applied in the deterministic model, sampling from the previously defined probability distributions. Stochastic results are assembled into insightful charts and used to analyze the most-relevant variables and correlations affecting the objective function.

Effect of an 860-m thick, cold, freshwater aquifer on geothermal potential along the axis of the eastern Snake River Plain, Idaho

A 1912-m exploration corehole was drilled along the axis of the eastern Snake River Plain, Idaho. Two temperature logs run on the corehole display an obvious inflection point at about 960 m. Such behavior is indicative of downward fluid flow in the wellbore. The geothermal gradient above 935 m is 4.5 °C/km, while the gradient is 72–75 °C/km from 980 to 1440 m. Projecting the higher gradients upward to where they intersect the lower gradient on the temperature logs places the bottom of the cold, freshwater Snake River Plain aquifer, which suppresses the geothermal gradient at this location, at least 860 m below the surface. The average heat flow for the corehole between 983 and 1550 m is 132 mW/m2. Although the maximum bottom-hole temperature extrapolated from a measured time–temperature curve was only 59.3 °C, geothermometers suggest an equilibrium temperature on the order of 125–140 °C based on a single fluid sample from 1070 m. Furthermore, below 960 m the basalt core shows obvious signs of alteration, including a distinct color change, the formation of smectite clay, and the presence of secondary minerals filling vesicles and fracture zones. This alteration boundary could act as an effective cap or seal for a hot-water geothermal system.

The Iceland Deep Drilling Project 4.5 km deep well, IDDP-2, in the seawater-recharged Reykjanes geothermal field in SW Iceland has successfully reached its supercritical target

Abstract. The Iceland Deep Drilling Project research well RN-15/IDDP-2 at Reykjanes, Iceland, reached its target of supercritical conditions at a depth of 4.5 km in January 2017. After only 6 days of heating, the measured bottom hole temperature was 426 °C, and the fluid pressure was 34 MPa. The southern tip of the Reykjanes peninsula is the landward extension of the Mid-Atlantic Ridge in Iceland. Reykjanes is unique among Icelandic geothermal systems in that it is recharged by seawater, which has a critical point of 406 °C at 29.8 MPa. The geologic setting and fluid characteristics at Reykjanes provide a geochemical analog that allows us to investigate the roots of a mid-ocean ridge submarine black smoker hydrothermal system. Drilling began with deepening an existing 2.5 km deep vertical production well (RN-15) to 3 km depth, followed by inclined drilling directed towards the main upflow zone of the system, for a total slant depth of 4659 m ( ∼ 4.5 km vertical depth). Total circulation losses of drilling fluid were encountered below 2.5 km, which could not be cured using lost circulation blocking materials or multiple cement jobs. Accordingly, drilling continued to the total depth without return of drill cuttings. Thirteen spot coring attempts were made below 3 km depth. Rocks in the cores are basalts and dolerites with alteration ranging from upper greenschist facies to amphibolite facies, suggesting that formation temperatures at depth exceed 450 °C. High-permeability circulation-fluid loss zones (feed points or feed zones) were detected at multiple depth levels below 3 km depth to bottom. The largest circulation losses (most permeable zones) occurred between the bottom of the casing and 3.4 km depth. Permeable zones encountered below 3.4 km accepted less than 5 % of the injected water. Currently, the project is attempting soft stimulation to increase deep permeability. While it is too early to speculate on the energy potential of this well and its economics, the IDDP-2 is a milestone in the development of geothermal resources and the study of hydrothermal systems. It is the first well that successfully encountered supercritical hydrothermal conditions, with potential high-power output, and in which on-going hydrothermal metamorphism at amphibolite facies conditions can be observed. The next step will be to carry out flow testing and fluid sampling to determine the chemical and thermodynamic properties of the formation fluids.

Transient flowing-fluid temperature modeling in reservoirs with large drawdowns

Modern downhole temperature measurements indicate that bottomhole fluid temperature can be significantly higher or lower than the original reservoir temperature, especially in reservoirs where high-pressure drawdown is expected during production. This recent finding contradicts the isothermal assumption originally made for routine calculations. In a high-pressure drawdown environment, the Joule–Thomson (J–T) phenomenon plays an important role in fluid temperature alteration in the reservoir. This paper presents a robust analytical model to estimate the flowing-fluid temperature distribution in a reservoir that accounts for the J–T heating or cooling effect. All significant heat transfer mechanisms for fluid flow in the reservoir, including heat transfer due to convection, J–T phenomenon, and heat transfer from overburden and under-burden formations, are incorporated in this study. The proposed model successfully validates the results of a rigorous numerical model that intrinsically honored field data.

Evaluation of geothermal heating from abandoned oil wells

Abstract With continuous petroleum exploitation, more and more oil wells have been abandoned, which contain abundant geothermal energy. For utilizing the geothermal energy, this paper presents a new geothermal heating system using abandoned oil wells (AOW), and a comprehensive model combing wellbore heat transfer, formation and building energy transport is built, parameters including geothermal production, room temperature and fluid production temperature are examined by the built model. Simultaneously, a formation temperature return model was developed to investigate the formation rewarming after heating period. Furthermore, the economic and energy analysis were performed to assessment the thermo-economic performance of the presented system. Particularly, an existing AOW with depth of 3000 m was concerned to heat a virtual building with heating area of 10000 m2. The results showed that the AOW could keep the building at around 26°C with water flow rate 20 m3/h, and the maximum heating area could reach 11000 m2. Also, the bottom-hole temperature could return to a steady point after the 2nd year. The total geothermal energy production was 5.5 × 1012J during heating period, which could reducing CO2 emission about 457 ton each year. Specially, the largest total annualized cost of the new heating system was about half of that of conventional heating system.

DETERMINATION OF NEAR WELLBORE ZONE PROPERTIES FROM NON-STATIONARY TEMPERATURE MEASUREMENTS IN THE WELL

Common method of accounting for the deterioration of the filtration properties of the reservoir is the in-troduction of a dimensionless coefficient - skin factor. Traditionally, in order to determine the value of skin factor hydrodynamic research methods (well test) at non-stationary modes are applied (pressure recovery curve, level recovery curve) are used. In recent years, along with the pressure in well logging, bottom hole temperature dynamics is also recorded, that allows to use this data for obtaining the additional information about the reservoir and is a slower process, also about near wellbore zone. In this paper the possibility of de-termining the radius of the zone of permeability deterioration in the near wellbore zone from the non-stationary temperature measurements in well is studied; and also the sensitivity of the inverse problem solution to variation of simulation parameters.

Advancement in Openhole Sand-Control Applications With Shape-Memory Polymer

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 181361, “Advancement in Openhole Sand-Control Applications With Shape-Memory Polymer,” by Xiuli Wang and Gbenga Osunjaye, Baker Hughes, a GE company, prepared for the 2016 SPE Annual Technical Conference and Exhibition, Dubai, 26–28 September. The paper has not been peer reviewed. Conventional openhole sand-control techniques include standalone screens, expandable screens, and openhole gravel packing (OHGP). In some cases, the uniformity, size, and level of compressive strength of the formation dictate the use of an OHGP completion. However, OHGP is not always feasible or practical for some reservoirs and geographic locations. Shape-memory-polymer (SMP) technology can fill the gaps that exist with current OHGP techniques. This paper summarizes a technology using SMP to provide downhole sand control in openhole environments. Introduction The SMP conformable sand-control system consists of an engineered polymer material compacted onto a retainer cartridge (outer shroud, plain Dutch-weave mesh, and inner shroud). The assembly is then installed onto a perforated base pipe by mechanical means to provide a simple modular system for openhole sand-control applications. SMP Principle and Engineered Behaviors. The SMP typically has two different states: the glass state at low temperatures and the rubber state at higher temperatures. The point of change of state (the transition from the glass state to the rubber state), and the associated temperature, is referred to as the glass transit temperature (Tg). The engineered SMP has a defined Tg—the point where shape recovery starts. The initial SMP is first heated to the Tg of the polymer. Then, a mechanical force is applied to compact it to a smaller diameter and onto a retainer cartridge. The condensed SMP is then cooled below its Tg, and the force is removed. The SMP retains its compacted size until the surrounding temperature of the SMP reaches the Tg, at which point shape recovery begins. The bottomhole temperature (BHT) of the candidate reservoirs needs to be lower than the Tg to ensure that the SMP is rigid under the downhole conditions during the production phase. After the SMP sand-control system is installed in a wellbore, to expand the SMP under a BHT that is lower than the Tg, an activation fluid must be introduced. This activation fluid serves as a catalyst and temporarily reduces the Tg below the BHT so the SMP will be recovered to its initial shape. After the SMP is deployed, the activation fluid is flushed out. The SMP retains its recovered shape that conforms to the wellbore, and it is ready for production.

Temperature Transients Affect Reservoir–Pressure Estimation During Well Tests: Case Study and Model

Summary This paper discusses how the pressure measured by the downhole gauges during a drillstem test (DST) is affected not only by hydrostatic, friction, or kinetic-energy pressure losses, but also by changes in temperature. In oil wells, the bottomhole temperature is decreasing when the pressure is building up after a flow period. The change in temperature is inducing a change in the wellbore-fluid density, itself affecting the bottomhole pressure. Most numerical-simulators modeling flow in pipes do not take into account this effect, because it is not significant for low- to moderate-productivity wells. In high-productivity wells, however, the temperature change can affect dramatically the bottomhole pressure measured above the reservoir, and the pressure can even decrease at the end of a static period. A mathematical model is presented to compute the pressure drop caused by the nonisothermal effects, and it can be used to correct the measurements. Field examples are discussed to illustrate this effect, and recommendations are made on how new technology can improve pressure measurements during well tests. To measure the effects on the pressure measurements caused by the position of the gauges in the DST string, two gauge carriers were run in some well tests in deepwater wells offshore Brazil, one at the level of the tester valve and one below the packer, as deep as possible in the test string. The gauges could transmit data with a wireless telemetry system that allowed the operator to monitor in real time the pressure changes and the difference between the two sets of gauges. In high-permeability wells, using the uncorrected pressure measured with a gauge 50 to 100 m above the reservoir, as is typically the case, can result in a wrong productivity index (PI) and, at times, in uninterpretable results. Locating pressure gauges as close to the reservoir as possible is crucial in high-permeability reservoirs, to minimize the measurement errors, but also to avoid misinterpretations when an obstruction forms below the tester valve. With the new wireless telemetry systems, it is possible to monitor in real time gauges mounted below the packer, much closer to the perforations than the standard gauges placed at the level of the tester valve, thus avoiding making wrong decisions during the test. A long pressure-transient test could be uninterpretable because the gauges are at the wrong depth. Ideally, the pressure gauges should be placed in front of the perforations, but it is not always possible. Therefore, nonisothermal effects on pressure measurements during a well test need to be clearly understood and taken into account when designing and interpreting well tests, particularly in high-productivity reservoirs.

Preliminary Findings into Thermal Properties of Specific Stratigraphy for Geothermal Energy Prospecting Along the Williston Basin

The paper focuses on the thermal evaluation of geological well data along the Williston Basin, possessing the greatest potential for geothermal energy development. The research follows the criteria for possible electrical generation through binary type systems for medium-temperatures exceeding 80℃. The bottom-hole temperatures (BHTs) obtained from the geological well data are corrected to thermal equilibrium through the Harrison correction method, from which the findings clearly point to the Estevan 103.5'W region, as the best geothermal energy prospect for a binary type system. Three wells having the highest recorded temperatures at depth are seen in particular with well locators of 101/11-14-002-09W2/00, 121/10-28-001-10W2/02, and 141/03-08-001-11W2/00 having temperatures of 106℃, 100℃ and 127℃ at depths respectively. The thermal distribution map serves as a preliminary tool for investigating the potential of the Williston Basin for geothermal energy development. These maps, coupled with hydraulic maps, can be used as an enhanced method of determining prospective site locations for wells. Finally, temperatures above 80℃ were found at depths exceeding 2250m for the Williston Basin, overlying the Winnipeg and Deadwood formations.

Comparison of numerical analysis on the downhole flow field for multi-orifice hydrothermal jet drilling technology for geothermal wells

Newly developed hydrothermal jet drilling technology has the potential of being economically advantageous over conventional drilling techniques for drilling deep wells in hard formations. By applying coiled tubing techniques and modulating fluid media in the bottomhole reaction chamber, there can be a high temperature and high velocity jet striking and conducting heat to break the rock. So far, there has been no specific study on the influence of nozzle structure on the flow field of multiple hydrothermal jets. This paper presents hydrothermal jet models with different numbers of orifices to investigate the features of flow field, carrying capacity, drilling ability and cooling effect. Results show that for two models in the absence of cooling water, the bottomhole center temperature and pressure are higher than the two sides under multiple hydrothermal jets conditions. This is similar to the flow pattern for a single jet. Additionally, for the five-orifice nozzle with cooling water injected, the entire high temperature region is cylindrical. Ambient cooling water envelops the inner hot water. By comparing different models, the five-orifice nozzle model without cooling water shows a circular symmetric distribution of the bottomhole temperature. With cooling water injected, the central high temperature region becomes rectangular, while the margin of the well bottom is cooled by the peripheral cooling water. The bottom rock average temperature in five-orifice model is lower than for the four-orifice model due to more drastic thermal and kinetic transfer between the hydrothermal jet and the cooling water. The five-orifice nozzle model is better than the four-orifice nozzle model in terms of bottomhole temperature, bottomhole pressure and carrying capacity. Therefore, the five-orifice nozzle should be adopted for hydrothermal jet drilling. It is also feasible to pump down relatively high temperature cooling water to guarantee the high temperature downhole environment. Meanwhile, the cooling water pressure should be controlled during the drilling process for better cooling efficiency. All results in this paper are relevant to the parameters design for multi-orifice hydrothermal jet drilling technology.

Development of a Novel Logging Tool for 450°C Geothermal Wells

Abstract Exploitation of super-critical water from deep geothermal resources can potentially give a 5–10 fold increase in the power output per well. Such an improvement represents a significant reduction in investment costs for deep geothermal energy projects, thus improving their competitiveness. The ongoing European Horizon2020 DESCRAMBLE (Drilling in dEep, Super-CRitical AMBients of continental Europe) project will demonstrate the drilling of a deep geothermal well with super-critical conditions (>374°C, >220 bar) by extending an existing well to a depth of around 3.5km. The drilling operation is depending on verification of the bottom hole pressure and temperature where state-of-the-art electronic logging tools cannot operate reliably. SINTEF has developed a novel pressure and temperature logging tool for this extreme environment. The target specification for the tool is 8 hours logging of temperature and pressure at 450°C and 450 bar. In this work, we describe the tool requirements and discuss the design choices made with emphasis on the electronics platform and limitations imposed by the available battery technology, as well as the casing and heat shielding. Test results of the tool are presented, including test data from a field-test in a 250°C geothermal well in Larderello, Italy.