In response to the borehole instability problems such as wellbore collapse and sand production, which often occur in drilling and completion, a thermosensitive screen technology that can expand spontaneously at a specific temperature has been developed. The radial expansion of the screen allows for annulus filling and borehole strengthening. This paper provides a theoretical evaluation of the comprehensive performance of the thermosensitive screen on wellbore collapse. The results show that the thermosensitive screen barely expands before reaching the conversion temperature, which facilitates the screen's descent into the target depth. After reaching the destination depth, it can be stimulated to expand under the influence of conditions such as formation temperature. The extruding stress after screen expansion contacting the wellbore wall can effectively improve the stress distribution around the near-wellbore and reduce the shear instability caused by the difference between the maximum and minimum principal stress of the formation, while at the completion stage of production, it can effectively improve the flowing downhole pressure, thus increasing the drawdown pressure.

Solids production is relatively uncommon in tight reservoirs, but it has been identified as a common problem in the fractured, superdeep, hot tight gas reservoirs in the Tarim Basin of China (TVD is 21,000+ ft., temperature is 320+ °F, closure stress is 20,000+ psi, formation pressure is 14,500+ psi, drawdown pressure is very low, etc.). We are investigating the fundamental mechanisms governing solids production in such reservoirs, and exploring for potential solutions. It is necessary to recognize the differences between failure mechanisms and sand production potential in unconsolidated/weakly consolidated sands and indurated, low permeability sandstones. We have observed several phenomena during and after fracturing in this high-temperature, low-permeability reservoir. These are: (1) there is a substantial difference between the formation temperature and bottomhole fluid treating temperature during fracturing, about 230+ °F; (2) the fracturing fluid has an high salinity (40% NaNO 3 was used to the fracturing fluid to increase weight/hydrostatic head in order to reduce surface treating pressure) and there has been a long interaction time due to partial flowback; (3) there is an extremely high gas production rate; and (4) on occasion, there has been aggressive and frequent bean-up or shut-in. After recognizing these complicating considerations, we analyzed their impact on rock integrity, and on the resistance to solids production (both proppant and formation). We are conducting an in-depth analysis of field observations of sanding. With this effort, we are attempting to develop solutions to mitigate or prevent sand production for future wells. There is a history of significant solids production. The large temperature difference between the static formation temperature and the fracturing fluid temperature incurs extreme thermal stress near the wellbore, and to a lesser degree, along the fracture. These thermoelastic/plastic effects may incur damage near the wellbore, through the completion and along the fracture surface. In addition, failure by shear or extension might be induced in the intact tight rock with extended contact with the high salinity base fracturing fluid. Hydrodynamic drag and significant energy expenditure due to high gas rates, non-Darcy losses, and in-situ erosion are anticipated. Some authors have coined a term, "C-Factor," to quantify this rate sensitive behavior. The "C-Factor" embodies the second order rate dependency of kinetic energy expenditures. With large velocities, kinetic energy expenditure is observed to be extremely high, and may be a root cause for damage to perforation tunnels and intact rock. In order to prevent solids production in the future, we may need to consider controlling salinity, production rate, the temperature of fracturing fluid, bean-up and shut-in frequency, along with standard geomechanical controls such as borehole trajectory. This paper speculates on some of the fundamental mechanisms governing solids production in extremely deep, high temperature, low permeability gas reservoirs; specifically the Tarim Basin.

In typical drill-stem testing (DST), transient pressures are gathered downhole while rate measurements occur at the surface. Adverse effects of heat transfer upon pressure, particularly during a buildup test in a gas well necessitate the close proximity of pressure measurements to the point of fluid entry. While pressure measurements are reliable with sufficient resolution in most settings, rate measurements often lack synergy with pressure due to the sensor resolution and frequency of monitoring. This lack of pressure/rate harmony may precipitate significant uncertainty in transient-test interpretations. This paper presents a case study for a deepwater asset in Western Australia, where temperatures were recorded at various depth stations in four wells, each in a different reservoir, before, during, and after transient testing, in addition to the traditional downhole pressure and surface rate measurements. This temperature data allowed estimation of gas flow rates. The flow rate accuracy increased at shallower depths because increased heat transfer enhanced the fidelity of measurements. Overall, the distributed temperature data allowed the estimation of both the static geothermal and the dynamic flow temperature gradients.

With ever increasing energy demands and the depletion of hydrocarbon resources, marginal fields play an important role in oil and gas exploitation. Flow assurance issues, including wax and hydrate formation, can be found in long distance tiebacks. Subsea processing, where processing equipment is installed on the seabed, can be used to solve these flow assurance issues in remote marginal fields. Subsea processing is the leading edge technology for unlocking production from reservoir under complex conditions. This paper demonstrates the opportunities in marginal field development, and analyses the implication of applying subsea processing in remote marginal fields. The marginal field case study concerns a development with an 80 km tieback, having reserves of 120 million barrels of oil and in water 3,000 m deep in the Gulf of Mexico. The technical and economic aspects of two field development options, one employing subsea separation and boosting, and the other, an electric trace heated pipe-in-pipe flowline and subsea boosting, are compared. Hydraulic analysis of three phase flow (oil, gas, and water) using state of the art simulation software (OLGA) is performed to demonstrate production fluid behavior inside the flowline. Life cycle cost, combining both economic (CAPEX and OPEX) and risk factors (RAM), are used as the selection criterion. Subsea separation with continuous hydrate inhibitor injection can prevent flowline blockage over the field life, while the electric trace heated pipe-in-pipe option may require subsea boosting to override the large pressure drop in late field life. In the analysis, subsea separation shows potential life cycle cost savings of up to 13% compared to electric trace heated pipe-in-pipe, indicating it may be the appropriate option when developing fields with these specific conditions. Improvement of subsea processing requires more compact designs for deepwater applications, which will help reduce both capital investment and intervention cost.

This work contributes to a concept proposal for obtaining pore fluid viscosity and formation permeability from thermoacoustic measurements (i.e., conducting acoustic logging of pore fluid mobility at different temperature conditions in the wellbore). The acoustic method for mobility estimation from Stoneley wave attenuation and dispersion is widely used in the industry. Currently, nearly all wireline measurements are performed at static thermodynamic conditions in the wellbore. But what happens if thermodynamic conditions are changed and logs are run at different temperature conditions at a given depth? In this case, the measurements of the pore fluid mobility at different temperatures allow obtaining additional information on the pore fluid viscosity and improve the accuracy of permeability estimation by the acoustic method. This work includes experimental and modeling verification of the suggested thermoacoustic method. The experiments were on laboratory core samples; finite-difference poro-visco-elastic code was used for the modeling. The applicability of the method is shown to be dependent on the temperature difference of the formation, accuracy of the Stoneley wave dispersion and attenuation measurements, and the in-situ wellbore pore fluid viscosity, temperature, and pore pressure.

Ground freezing technology has been applied in Colorado oil shale formation to control ground-water flow for Shell's In-situ Conversion Process (ICP). The circulation of coolant through subsurface pipes causes the formation water to freeze and plug off permeable channels, and results in an impermeable flow barrier (also known as a freeze wall). The freeze wall will be used to isolate the developing area from the undeveloped area for ground-water protection and product containment. Because the ground freezing in our application is intended to be operated in conjunction with ICP, there is a need to develop an integrated reservoir simulation model with the capabilities for both freezing and in-situ conversion processes. This paper describes the development of a reservoir simulation model for ground freezing process. It also discusses some of the simulation challenges of ground freezing process in a reservoir simulator. The developed model has been calibrated with data from a 2003 field test and used to assess the sensitivity of freeze wall closure time with respect to freeze-hole spacing, initial formation temperature, ground water flow strength (hydraulic conductivity and gradient), and water salinity etc. The simulation results revealed that the freeze-wall closure time depends strongly on freeze-hole spacing, water seepage rate and formation temperature.

Abstract This paper presents a transient wellbore simulator coupled with a semianalytic temperature model for computing wellbore-fluid-temperature profile in flowing and shut-in wells. Either an analytic or a numeric reservoir model can be combined with the transient wellbore model for rapid computations of pressure, temperature, and velocity. We verified the model with transient data from multiple gas and oil wells, where both surface and downhole data were available. The accuracy of the heat-transfer calculations improved with a variable-earth-temperature model and a newly developed numerical-differentiation scheme. This approach improved the calculated wellbore fluid-temperature profile, which, in turn, increased the accuracy of pressure calculations, at both bottomhole and wellhead. The proposed model accurately mimics afterflow during surface shut-in by computing velocity profile at each timestep and its consequent impact on temperature and density profiles in the wellbore. Surrounding formation temperature is updated every timestep to account for changes in heat-transfer rate between the hotter wellbore fluid and the cooler formation. Optional hybrid numerical differentiation routine removes the limitations imposed by the constant relaxation-parameter assumption used in previous analytic-temperature models. Introduction Modeling of changing pressure, temperature, and density profiles in the wellbore as a function of time is crucial for design and analysis of pressure-transient tests, particularly when data are gathered off-bottom or in deepwater setting, and identifying potential flow-assurance issues. Other applications of this modeling approach include improving design of production tubulars and artificial-lift systems, gathering pressure data for continuous reservoir management and estimating flow rates from multiple producing horizons. A coupled wellbore/reservoir simulator entails simultaneous solution of mass, momentum, and energy balance equations, providing pressure and temperature as a function of depth and time for a predetermined surface flow rate. Almehaideb et al. (1989) studied the effects of multiphase flow and wellbore phase segregation during well testing. They used a fully implicit scheme to couple the wellbore and an isothermal black-oil reservoir model. The wellbore model accounts only for mass and momentum changes with time. Similarly, Winterfeld (1989) showed the simulations of buildup tests for both single and two-phase flows in relation to wellbore storage and phase redistribution. Fairuzov et al. (2002) model formulation also falls into this category. Miller (1980) developed one of the earliest transient wellbore simulators, which accounts for changes in geothermal-fluid energy while flowing up the wellbore. In this model, mass and momentum equations are combined with the energy equation to yield an expression for pressure. After solving for pressure, density, energy, and velocity are calculated for the new timestep at a well gridblock. Hasan and his coworkers presented wellbore/reservoir simulators for gas (1996), oil (1997) and two-phase (1998) flows. Their formulation consists of solution of coupled mass, momentum, and energy equations, all written in finite-difference form, and requires time-consuming separate matrix operations. In all cases, the wellbore model is coupled with an analytic reservoir model. Fan et al. (2000) developed a wellbore simulator for analyzing gas-well buildup tests. Their model uses a finite-difference scheme for heat transfer in vertical direction. The heat loss from fluid to the surroundings in radial direction is represented by an analytical model. In this study, a wellbore/reservoir simulator including energy calculations is developed. In this formulation, unlike that presented by Fan et al., finite difference forms of mass and momentum equations are coupled with a semianalytic heat-transfer model, which can represent heat transfer in both vertical and radial directions. The solution of the finite-difference equations can be handled by one of the three matrix solvers, which is specified by the user. Matrix operations are not required for energy calculations because of the semianalytic formulation. This efficient coupling with the semianalytic heat-transfer model increased the computational speed significantly.

Abstract A few of the lost circulation incidents that have occurred at the Statfjord field and the Veslefrikk field appeared to have been caused by drilling through cooled formations. These lost circulation incidents have been analyzed and compared with offset wells drilled with full returns. We have made plausible that the presented cases of lost circulation are caused by the fact that these wells have been drilled too close to a water injector. Injection data have been analyzed to determine the thermo-elastic stress changes around these injectors. To quantify the thermal cooling effect, downhole pressure data measured during the mud loss incident are analyzed. We found a significant reduction both in the breakdown pressure and minimum horizontal stress. When comparing these data with a thermo-elastic model, the theory predicts a much stronger effect than the interpreted downhole pressure measurements. Numerical simulations of near-wellbore thermal stress effects showed that differences between the mud temperature and the formation temperature could significantly increase the wellbore stresses toward compression. However, the combined near-wellbore thermal effects of formation cooling and a warm mud could not explain the discrepancy between the model and the interpreted stress measurements. Introduction The Statfjord field and the Veslefrikk are two mature oil fields located (mainly) on the Norwegian continental shelf. At the Statfjord field the oil production started in 1979 and the Veslefrikk oil production started in 1989. Water and gas injection forms an important part of the drainage strategy for both fields. To date the recovery factor for Statfjord field is 63% and for the Veslefrikk field it is 38%. Both fields have an active infill drilling program of about 15 wells per year at the Statfjord field and 4 wells per year at the Veslefrikk field. Drilling wells in a mature field with water injectors poses a special risk for mud losses. Water injection causes cooling of the formation, which in turn changes the in-situ rock stresses. The thermal stress reduction can be so strong that the mudweight window reduces to zero. Normally, thermal stresses are not taken into account for mudweight window prognoses. The effect of reservoir depletion on the reduction of the fracture gradient is well established, however, the effect of formation cooling has been ignored for a long time. In analysis of the performance of water injectors, the effect of temperature has been long recognized. During injection of seawater, reservoir cooling significantly reduces the fracture stress causing thermal fracturing 1–3 . In drilling, several authors have investigated thermal effects caused by difference in temperature between the mud in the wellbore and the formation 4–7 . These thermal effects can be important when drilling with narrow mudweight windows, such as in depleted reservoirs 6 and in HP/HT reservoirs 5,7 . In the present paper we show another thermal effect that is new: the consequences of thermal stress changes resulting from drilling into formations that are cooled by a nearby water injector. In the paper we show examples of wells where lost circulation occurred because they were drilled into cooled formations. The losses were so severe that the wells had to be plugged back and sidetracked. After a description of the operations, the water injectors are analyzed in more detail to determine how close one can drill to a water injector without risking mud losses. For the wells having experienced mud losses, the downhole pressure data are analyzed in order to quantify the possible extent of the effect of formation cooling. Finally the near-wellbore stress changes caused by the combined effect of formation cooling and warm mud are analyzed by numerical simulation. The results are compared with the field data and discussed. Mud Loss Incidents Caused by Formation Cooling We have selected three wells from the Statfjord field and one from the Veslefrikk field that were candidates for mud losses due to drilling into cooled formations. For all four wells we have also analyzed offset wells for comparison, which were the successful sidetracks that were drilled with full returns afterwards. Wells A-15C and A-29A were drilled at the Statfjord field while wells A-11A and A-11B were drilled at the Veslefrikk field. Fig. 1 shows a depth structure map with some of the wells drilled from the Statfjord A platform. Table 1 lists the mudweight data for the investigated wells.

This paper was prepared for presentation at the 1999 SPE Annual Technical Conference and Exhibition held in Houston, Texas, 3–6 October 1999.

Abstract The paper describes a new approach used to select fracture fluid systems by applying fuzzy logic for fracture treatments. Based on the given formation information, the system first determines base fluid, viscosifying method, and energization method. Secondly, the system chooses the 3 to 5 best combinations of the possible fluids. Then, the system determines polymer type and loading, crosslinker, gas type if necessary, and other additives for the fluid systems. At the same time, the system also checks the compatibility of the fluid and additives with formation fluids and composition. The fuzzy logic system described in this paper, which is consisted of several fuzzy logic evaluators, can be applied to study, evaluate, and determine the best fluid systems to stimulate oil and gas production or water injectivity in wells. The approach can be extended to the solution of many other similar problems associated with drilling, completing, and working over wells. Introduction Hydraulic fracturing is one of major methods to increase reservoir production. The success or failure of a fracture treatment heavily depends on the fracturing fluids and additives used in the treatment. Choosing the correct fluid and additives is extremely important to ensure that the formation is not damaged, proppant is placed in formation as designed, and the fluid breaks and cleans up properly. Fracturing fluids are used to create fractures and to transport proppant down the tubular goods, through the perforations, and deep into the fracture. To pump a successful fracture treatment, an ideal fracturing fluid should have the following characteristics. – The fluid should be compatible with the formation and the reservoir fluids. – The fluid should be able to maintain sufficient viscosity at reservoir temperature, so it can suspend proppant and transport it deep into the fracture. – The fluid should be capable of developing the necessary fracture width to accept proppants or to allow deep acid penetration. – The fluid should have low fluid loss properties or high fluid efficiency. – The fluid should be easy to remove from the formation and have minimal damaging effects on both the proppant and the formation. – The fluid should be easily pumped down the wellbore and exhibit minimal friction pressure losses in both the pipe and the fracture. – The fluid should be easy to prepare and safe to use. – The fluid should be low cost. Currently available fracturing fluids seldom satisfy all of the above requirements. Of these, however, the most important requirements that we have to consider when selecting a fracturing fluid are (1) the ability to maintain sufficient viscosity at reservoir temperature and (2) compatibility with the formation and reservoir fluids. Fracture fluids can be divided into four groups: water-based fluids, oil-based fluids, foam-based fluids, and alcohol-based fluids. Table 1 describes these fluid types, and the conditions under which they are most often used. The selection of optimal fracturing fluids for a formation is based on consideration of the following factors: formation pressure, water sensitivity of the formation, formation temperature, permeability, and the fracture half-length to be created. Laboratory testing and field experience provide important information that must be considered when choosing a fracture fluid. These decisions are crucial to the success or failure of the stimulation treatment, and require comprehensive data sets, knowledge, and experience. P. 293

Abstract Heat loss from the wellbore fluid depends on the temperature distribution in the formation. Formation temperature distribution around a well was modeled by Ramey (1962) by assuming a vanishingly small wellbore radius. The assumption, while robust for some cases, could lead to unrealistic predictions of early-time behavior. This paper uses a rigorous model of heat transfer paper uses a rigorous model of heat transfer developed with consideration for the appropriate boundary conditions; that is, the heat transfer at the formation/wellbore interface is represented by the Fourier law of heat conduction. The superposition principle is used to account for the gradual change in heat transfer rate between the wellbore and the formation. The results of the new analysis are in agreement with the classical work of Ramey for large times (dimensionless time, tD greater than 10) However, significant differences are noted between the proposed solution and that of Ramey's log-linear approximation at small (tD less than 1.0) times. These differences may have considerable effect on certain applications, such as static earth temperature estimation from temperature logs, and bottomhole temperature estimation for cyclic steam injection. We also present an approximate algebraic expression for the rigorous integral solution of dimensionless formation temperature, TD. This simplified expression is accurate for most engineering calculations. Use of this solution is shown in the second part of the paper where the wellbore fluid temperature distribution is computed during two-phase flow. Introduction The importance of various aspects of heat transfer between wellbore fluid and the earth has generated a rich literature on the subject. Carslaw and Jaeger have covered such fundamental concepts of thermal diffusion as linear flow of heat in a rod with constant temperature and flow of heat in regions bounded by a cylinder. These concepts were later modified and extended to the cases of heat loss in both oil and geothermal wells. P. 469

Abstract This paper will present a mathematical and numerical model to simulate temperature and pressure behavior and their interference including the effect of fracturing fluid compressibility during a minifrac pressure test. The numerical solution and the approximate analytical solution of the Perkins-Kern-Nordgren 1,2 (PKN) model were employed to calculate the fracture geometry, namely fracture length, L, and width, w, before shut-in. After shut-in, linear elastic theory was used to calculate the fracture width from simulated pressure. The results of the model indicate that the fracture temperature changes significantly during a minifrac test, and the pressure is higher and declines at a slower rate for a compressible fluid compared with an incompressible fluid. The fluid loss coefficient estimated from the pressure decline by the standard analysis will be low if the fluid is compressible. This effect tends to be more severe if the fluid is confined (i.e., the fluid loss coefficient is low). In extreme cases of a highly, compressible fluid and a low fluid loss coefficient, the model predicts that pressure can actually increase after shut-in. Most importantly, it is observed from this work that the error in estimating the fluid loss coefficient, using the standard analysis, decreases when shut-in time increases. Therefore, the error in estimating the fluid loss coefficient can be minimized by using pressure data from later in the shut-in period. INTRODUCTION The standard analysis of the pressure decline in a minifrac test, originally developed by Nolte 3 in 1979, assumes that the fracturing fluid is incompressible after shut-in as the fracture closes. In this analysis, the net pressure is predicted to decline linearly with the square root of time after shut-in; from the slope of Î"P versus t plot, the fluid loss coefficient is estimated. However, when the fracturing fluid is compressible and significant warming of the fracturing fluid occurs after shut-in due to the surrounding higher-temperature formation, the analysis method can lead to an inaccurate estimation of the fluid loss coefficient because the thermal expansion of a compressible fracturing fluid will contribute to the pressure behavior during the test.

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. This paper was prepared for the 42nd Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Houston, Tex., Oct. 1–4, 1967. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract Knowledge of the actual temperature of a fluid in a fracture created with hydraulic pressure has been non-existent. The significance of having this data lies in the advantages of being able to predict not only acid spending times and related retardation effects, but also the viscosities of fracturing fluids. Viscosity values enter into the "C" factors used in fracture area calculations. Thus, an estimated viscosity can greatly affect predicted fracture areas and subsequently expected production increases. This work develops a method of calculating temperatures of injected fluids at a given distance from the well bore in a fracture, and suggests how this information may be used fm better stimulation techniques. Introduction In the design of treatments for oil and gas wells no technique has been available to predict the temperature of the stimulation fluid as it moves outward in a fracture; yet the effect of temperature on acid spending times and on the viscosity of fracturing fluids is no mystery. Calculation procedures and chemical mixtures have been designed simply for original bottom-hole temperatures. It is known, however, that formation cooling takes place as a cool fluid is pumped down a well and into the formation. By assuming that any chemical or physical reactions occur at original formation temperature a temperature estimate may be in error as much as 260 deg. F, thereby affecting decisions as to the type of and retarder needed, and estimates of fluid viscosity and density which are temperature dependent. The evaluation of the transient temperature distribution of fracturing fluid during a fracturing operation is a complex heat transfer problem. Certain assumptions regarding the nature of fluid flow in the fracture, and the mechanisms of heat transfer in both the fracturing fluid and the formation are necessary for the solution. The most accurate analysis of the problem requires the use of transient numerical procedures which involve the simultaneous solutions of a number of linear differential equations which describe the heat flow in both the fluid and the formation. Because of the heterogeneous nature of reservoir rocks, an averaging of the thermodynamic properties of the rock is necessary, and such variables create error in the cumbersome and exacting solution mentioned above.

Publication Rights Reserved Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and considered for publication in one of the two SPE magazines with the paper. Abstract A study has been made to try to improve the determination of water saturation of a given zone by use of the SP log. A method has been derived which appears to be an improvement in previous methods. Previous studies have shown that the formation water resistivity, a needed factor in the Archie equation for determining water saturation, is related to the magnitude of the SP deflection and to the mad filtrate resistivity by a coefficient which is a function of formation temperature. Evidence has indicated that this coefficient also varies with geographical location. An attempt was made to find a variable which would express this apparent variation in geographical location. The formation resistivity factor was selected and found to be satisfactory. The resulting empirical correlation relates the SP coefficient, formation temperature, and the formation resistivity factor. For the data used, this method produced results which were better than those of previous methods. An experimental study has been made which tends to confirm the trends and influences discovered in the empirical work. Introduction In order to calculate the formation water saturation using the familiar Archie equation, ................(1) the formation resistivity factor, F, the formation water resistivity, Rw, the true formation resistivity, Rt, and the saturation exponent, n, must all be determined or estimated. Values for Rw and Rt may be estimated by use of logs and correction and correlation charts. Values for F and n are usually determined from core analyses, or they may be estimated from logs and/or correlation charts. The accuracy of the estimated values of Rt, F, and n is usually 30%, but the approximated value of Rw is often in error by more than 100 percent. An incorrect assumption of Rw may lead to a very large error in Sw. Many times water resistivities can be measured from DST samples from the well in question or from the same zone in nearby wells.