The significant temperature difference between the fractured and non-fractured regions during the stimulation fluid flow-back period can be very useful for fracture diagnosis. The recent developments in downhole temperature monitoring systems open new possibilities to detect these temperature variations to perform production logging analyses. In this work, we derive a novel analytical solution to model the temperature signal associated with the shut-in during flow-back and production periods. The temperature behavior can infer the efficiency of each fracture. To obtain the analytical solution from an existing wellbore fluid energy balance equation, we use the Method of Characteristics with the input of a relevant thermal boundary condition. The temperature modeling results acquired from this analytical solution are validated against those from a finite element model for multiple cases. Compared to the warm-back effect in the non-fractured region after shut-in, a less significant heating effect is observed in the fractured region because of the warmer fluid away from the perforation moving into the fracture (after-flow). Detailed parametric analyses are conducted on after-flow velocity and its variation, flowing, geothermal, and inflow temperature of each fracture, surrounding temperature field, and casing radius to investigate their impacts on the wellbore fluid temperature modeling results. The inversion procedures characterize each fracture considering the exponential distribution of temperature based on the analytical solutions in fractured and non-fractured regions. Inflow fluid temperature, surrounding temperature field, and after-flow velocity of each fracture can be estimated from the measured temperature data, which present decent accuracies analyzing synthetic temperature signal. The outputs of this work can contribute to production logging, warm-back, and wellbore storage analyses to achieve successful fracture diagnostic.

The effects of horizontal well geometry remain debatable in most production modeling works. Most of recent reports fail to mention the effects of well geometries, especially in severe slugging cases. This study presents a qualitative comparison between different well geometries and their impacts in production performance of horizontal wells. The study utilizes a transient multiphase simulator to mimic the production from a horizontal well over a 12-hour period. The well has a 2-7/8″ ID tubing with TVD of approximately 5000 ft and MD of 10000 ft and maximum inclination angle of 10º within the horizontal section. The trajectories of horizontal section in the well include 5 cases, 5 undulations, hump (one undulation upward), sump (one undulation downward), toe-up and toe-down. These configurations are the representative examples of horizontal wells. A reservoir with a given deliverability equation and several perforation stages is used to provide well inflow. The impacts of reservoir deliverability, GOR, pressure and temperature are studied for all well geometries. The simulation results offer some valuable insights into the effects of well trajectory on production performance, including borehole pressure profile, liquid holdup, gas and liquid rate variations with time, and cumulative gas and liquid production. At high production rates, severe slugging is not observed, and thus, the well geometry effects are minimized with a consistent production at the surface. However, toe-up configuration exhibits a slightly better performance than the others. As the productivity and pressure reduces throughout the life of a well, the impacts of well trajectories become clearer. The presence of severe slugs and blockage of perforations near the toes causes a noticeable drop in production. During severe slugging, the pressure profile reveals longer fluctuation cycles, resulting in extreme separator flooding issues. The slugging frequencies are compared among different well geometries. Toe-down case exhibits lower slugging severity. As a result, toe-down well produces the highest cumulative liquid and gas rates. The presence of liquid blockage is observed in lateral and curvature sections. The toe-up and hump configurations exhibit the most severe slugs with minimum cumulative gas and liquid productions. The differences in productions among well trajectories exceed 30% under different well configurations. With the augmented growth of production from unconventional reservoirs, horizontal well technology has grown in oil and gas industry, yet study of well geometry in production system remains to be limited. This study is a unique effort to optimize well configuration and perforation placement in order to alleviate multiphase flow problems in the wellbore. Providing the practical potential on simulation works, this study provides a predictive guidline to connect well geometry selection and production optimization.

The separation of gas from gas-liquid mixture in horizontal wells has become a growing concern in the oil and gas industry. The produced free gas reduces the efficiency of rod pump systems, minimizes oil production and can lead to the failure of the rod pump system due to gas locking phenomena. The impact of two-phase flow on the new horizontal well gas anchor’s performance was investigated experimentally. Each experiment was conducted in a transparent horizontal well flow loop by using water and air as the test fluids. Experiments with and without the new gas anchor in the flow loop cases were studied. The new tool has two mechanisms to prevent gas phase from entering the tubing. The first mechanism is the breakage of the mixture’s wave by the bull plug of the tool. The second mechanism is the separation of small gas bubbles due to the flow through the tortuous path inside the tool. This experimental program quantifies the tool performance regarding the first working mechanism only. The bubble separation via the tortuous path mechanism was not investigated. The results showed that both with and without tool cases can separate 90 – 100% gas from the mixture, if the inlet of tubing or the tool was fully submerged under liquid phase of the mixture at all time. This condition was achieved under stratified flow where the horizontal part of the well was toe flat or toe-up (0°, +1°, and +2°). The wave breakage mechanism by the bull plug of the tool was confirmed visually. This breakage mechanism established the advantage of using the new gas anchor over no-tool condition.

Understanding the behavior of water-in-crude-oil emulsions is necessary to determine its effect on oil and gas production. The presence of emulsions in any part of the production system could cause many problems such as large pressure drop in pipelines due to its high viscosity. Electrical submersible pumps (ESPs) and gas lift are commonly used separately in lifting crude oil from wells. However, the use of downhole equipment and instruments such as ESPs that cause mixing can result in the formation of an emulsion with a high viscosity. The pressure required to lift emulsions is greater than the pressure required to lift non-emulsified liquids. Lifting an emulsion decreases the pressure drawdown capabilities, lowers production rate, increases the load on the equipment, shortens its life expectancy and can result in permanent equipment damage. Methods and apparatus which reduce the load on the pump, therefore, are desirable. The present paper is directed to understand the behavior of water-in-oil emulsions in artificial lift systems, mainly through gas lift. Two stable water-in-oil synthetic emulsions were created in the laboratory and their rheology and stability characteristics were measured. One contained crude oil and the other, mineral oil. The second stage included measuring the effect of gas lift exposure on the emulsion behavior and characteristics. The results of the present work indicate that water-in-oil emulsions can be destabilized, and their viscosities lowered under gas exposure. The effect of gas injection on the emulsion was linked to the initial conditions of the emulsion as well as the gas type, injection rate and exposure time. The present study is directed to methods and systems for combining both ESPs and gas lift for the purpose of improving and simplifying the lift of water-in-oil emulsions from oil wells. The novel methods and apparatus are based on the discovery that by adding gas above the ESPs in the wellbore, the viscosity of an oil-in-water emulsion is actually reduced, thus making it easier to lift oil from the well and extending the life of the ESP. Therefore, in addition to the normal benefits of gas in aiding the lift of liquids, if the gas lift valve is installed at a calculated distance above the pump location, the emulsion viscosity can be reduced. This reduces the load on the ESP.

Using optical fibers to instrument hydraulically fractured wells is becoming routine in US unconventional plays. Instrumented wells facilitate understanding of proppant distribution among perforation clusters and the inefficiencies of geometric fracturing and well planning techniques. However, converting fiber-optic data into proppant distribution requires management of high volumes of data and correlation of the data to factors such as well conditions, fracturing parameters, and temperatures. A user-friendly workflow for understanding hydraulic fracturing proppant and slurry distribution among different perforation clusters over time is presented. Ideally, slurry flow is equal between perforation clusters and, at least, constant in time, but the reality is very different. The interpretation workflow is based on proprietary algorithms within a general wellbore software platform and aims to greatly expedite the analysis. We propose using distributed acoustic sensing (DAS) data (in the form of custom frequency band energy (FBE) logs), distributed temperature measurements (DTS) and surface pumping data to obtain a quantitative analysis of proppant distribution within minutes, with various options for reporting and visualizing results. The software platform selected provides data integration, visualization, and customization of in-built algorithms. The new workflow enables users to upload DAS, DTS, flow rate, pressure, and other measurements and use customized algorithms to quantitatively analyze proppant distribution, enabling decisions in real time to optimize the fracturing operation. The validity of the approach is illustrated by a case study involving a well with 28 stages and four to five clusters per stage. The workflow is automated to provide results in real time, enabling quick corrective actions and significantly improving the efficiency and economics of hydraulic fracturing.

Over the past 20 years the industry has focused on drilling and completing horizontal producing wells, in order to develop better deliverability and better UER across the reservoir. The past 10 years igniting the unconventional reservoirs across the US the majority of wells drilled and completed are horizontal wells. These types of wells are traditionally drilled with various inclinations, trajectories which porpoise across the reservoir interval. Horizontal lateral sections consist of numerous selectively stimulated stages containing greater than 20 stages spread out across 2,000 ft to 15,000 ft of horizontal interval. In order to understand how a producing horizontal lateral section contributes, is to deploy production log technology across the lateral while the well is flowing back. The production log system & survey is the only direct method to measure the performance of the well, how each stage and perforation cluster contributes, oil, water and gas. The production log tool comprises of various measurements such as fluid capacitance, fluid density, holdup, which measures the oil, water gas content, cross sectional holdup and velocity as fluids enter the lateral section. The production log system can be deployed with two separate methods, coiled tubing deployment or wireline with a well tractor situated on top of the production log tool string. It is highly recommended that the production log survey be performed using a procedure and program created by an experience specialist production logging personnel. This will increase the probability the service will deliver a representative result & value to the oil company. However, whether by customer decisions, inadequate service company knowledge, lack of experience in how the tools and deployment methods should be run & how the well should be performing during the survey; the production log surveys, at time may not deliver a quality product. A full service production log service including deployment, the price point offering is ~ $100,000 to > $1,000,000. A slip up in service quality leads to the service not being performed in the future or leaves a negative view on the service over all. This paper will discuss the benefits pit falls of horizontal production log survey application, deployment & acquiring quality results. The paper will show case examples of productions logs run with various deployment methods & identify benefits and issues during the survey. This paper will present a best practices novel procedural flow-chart for the industry to follow, that can assist and help production logging, wireline, tractor, coiled tubing deployment service companies, and the oil company engineering group to execute properly a quality production log service survey.

Low concentration particle transport in multiphase horizontal pipes in the presence of a viscous liquid is experimentally investigated using a 0.05 m diameter pipe. The experiments were conducted for a wide range of liquid and gas flow rates in both intermittent and stratified flow. Critical velocity was defined as “minimum required liquid and gas flow rates to keep particles constantly moving in the pipe”. Critical velocity is defined in a way to make sure all particles are continuously moving along the pipe and as a result prevents forming a stationary bed of sand. The experimental data obtained in the current study shows that the required gas flow rate to meet critical velocity definition increases by decreasing liquid flow rate. Moreover, the effect of physical parameters such as sand concentration, sand size and liquid viscosity is also experimentally investigated. The experimental data obtained in this study shows that critical velocity is a function of sand concentration and sand size and increases by increasing either within the examined range of particle concentration and size. Regarding the effect of carrier liquid viscosity, the experimental data reveals that by increasing viscosity the minimum required flow rates to constantly move sand along the pipe increases.

The optimization of stimulation treatments in Mexico has required the use of novel diversion technologies to increase the productivity of wells by improving the coverage of stimulation fluids and reducing completion costs. Self-degrading particulate has become widely used in the country because of the diverter flexibility. Job experiences range from hydraulically fracturing unconventional reservoirs to the matrix acidizing of naturally fractured carbonate formations. The purpose of this paper is to verify the effectiveness of this material for achieving the selective stimulation of multiple intervals, either in horizontal or vertical wells. Because there is no confidence in a complete stimulation of all open intervals, diagnostic techniques have been implemented to determine the effectiveness of diversions. For near-wellbore (NWB) monitoring, technologies such as radioactive tracers and distributed temperature sensing (DTS) have been used to determine treatment fluid locations after the application or in real-time. Downhole microseismic monitoring has been performed for far-field indications of diversion success in hydraulic fractures of vertical wells with multiple intervals open at the same time. This paper discusses four wells from the north, central, and south regions in Mexico. All of them have completely different reservoir properties and completion types. Improved production increase was the main difference between wells where diversion with self-degrading particulate diverters was used compared to those that were not treated with diverters; a production increase from 30 to 70% was achieved. Completion time was reduced with the implementation of the novel self-degrading particulates vs. other possible methods, allowing faster return of investment (ROI). Real-time decision making could be performed using both a diverter and monitoring techniques to assure a uniform treatment placement. Another differentiator was the simple logistics required to handle the material compared to other additives employed in the past. Because of the performance of the diverter, it has been applied in more reservoirs with extremely variable permeabilities across the country (tight gas and oil sandstones, gas and oil shales, and naturally fractured oil-bearing carbonates). Downhole temperature is the main controlling factor to accelerate or retard the degradation of the particulate, as it must take into account that in cooler formations, longer times are required to achieve complete degradation. Its independence of the wellbore geometry has increased the implementation in openhole and cased-hole completions, despite the final shape of the perforations.

Mature gas wells tend to suffer from flow rate fluctuations due to an inability to remove liquids. Flow-rate stabilization is essential for profitable operation of these wells. Moreover, the use of nozzles can help make in-situ foam treatments more efficient. The combined use of venturi nozzles and foamers is proposed as a novel artificial lift method. The effect of downhole venturi nozzles on flow stabilization of gas wells has been experimentally investigated. Air-water flow was studied in a 2″ vertical pipe. The effect of the nozzles on in-situ foam generation was also studied. Using the principles of Nodal Analysis, it was observed that the use of downhole venturi nozzles significantly improved the stability of production. The nozzles induce back-pressure on the flow inlet. The smaller the throat diameter is, the greater the back-pressure is. Therefore, proper sizing of the nozzle is important. Flow through the nozzles was characterized using CFD simulations and a sizing methodology has been proposed. Foam flow was studied for injection before and after the nozzle at very low concentrations of a commercial foamer. The presence of the nozzle during foam flow did not affect the pressure gradient or holdup characteristics significantly when compared to foam flow without nozzle. However, the foam stability and quality were affected by the nozzle, depending upon the position where the foamer was injected (either before or after the nozzle).

Liquid loading is the inability of a riser or gas well to produce liquids, resulting in reduction of gas production in mature gas fields. Mechanisms describing liquid loading initiation are not well understood for inclined pipes or deviated wells. Knowing the effect of pipe inclination over the liquid-loading initiation will help for the development of a predictive tool for flow assurance, well production forecast as well as remediation techniques enhancing gas production. An experimental study of low liquid loading has been conducted for 90°, 75°, 60° and 45° inclined pipes. Air/water flow in a 3-in ID pipe has been investigated. Pressure gradient and average liquid holdup were measured. Visual observations with high and low speed cameras have been recorded to identify flow patterns and liquid film behavior for each test point. Pipe inclination effects on critical gas velocity for flow pattern transition have been investigated. The critical gas velocity represents the maximum gas flow rate where the liquid loading is observed. This critical velocity increases as pipe inclination deviates from vertical. Pressure gradient fluctuations and liquid film flow behavior are closely related with liquid loading initiation. As the pipe deviates from vertical and owing to the increasing liquid film thickness at the bottom of the pipe, slug and churn flow patterns are promoted. Therefore, the existing critical velocity prediction models, which ignore the circumferential variation of film thickness, produce significantly different values of critical velocities when compared with the experimental data. Liquid loading is one of the main problems that the industry faces during the production of natural gas wells and transportation of low liquid loading gas-liquid flow through a riser. This study serves as a foundation for future model developments to avoid and remedy liquid loading related problems in risers and gas wells.

The effect of pipe diameter on liquid loading initiation has been experimentally investigated using 2-in and 4-in pipe diameters. Two-phase flow parameters such as pressure gradient and liquid holdup were measured. Flow characteristics were determined by visual observation using a high speed video camera. Critical gas flow rate for liquid loading initiation has been identified and comparison between the two pipe diameters is presented. The critical superficial gas velocity corresponding to the minimum pressure gradient is larger for the smallest diameter. When the comparison is carried out in terms of mass flow rates, critical flow rate for liquid loading in 2-in pipe is smaller than that in 4-in. pipe. This supports the use of velocity strings to extend the production life of the gas well. Additionally, comparison of the data with available mechanistic models prediction shows significant discrepancies. Possible reasons for these discrepancies are presented.

To perform a successful optimization of large and complex production facility, there should be a good communication between engineers at different departments (Reservoir, Production, Geological, etc). However, as a common practice, their decision making process is separate from each other. This may result in under-designing such as flow bottlenecks or over designing, which imposes unnecessary expenditures. This lack of communication can be alleviated by coupling the reservoir flow model to the facility network by means of enhancements in software development that can perform networking analysis in an effective manner. This paper presents a work methodology and recommendations through a case study to develop an offshore field that contains both heavy and medium oil. First, commercial software is utilized to build the model according to the input data. Subsequently, a development plan has been suggested for this field and number of wells to be drilled in the reservoir has been determined. Then sensitivity analysis is performed to find out the best possible scenario to produce from the field. Economical analysis is performed for each case to assure profitability. According to the available recoverable reserves, a 13 year production plan is proposed (average of 7.46% per year). Simulation results indicate that by the proposed scenario at least 20% more of total recoverable reserves can be produced over this period. The highest oil rate is observed at the end of fourth year (98000 STB/d), when the field is mainly developed. This case study shows that complex production systems can be modeled by commercial software, which leads into better production forecasts. In addition, it can help us in selecting proper down-hole equipments and predicting the possible problems in each well (such as sand production or asphaltene deposition in this case).

Production logging uses measurements to understand the velocity & fluid types comingling as open reservoir intervals deliver products which begin to flow up hole. In a horizontal flowing well environment, the logging tools of choice can be individual discreet measurements situated across the cross sectional flow area to measure and define the fluid type & velocity. Flow measurements are much more difficult to measure as most horizontal flowing environments are not stable. Deployment of this tool type can be conveyed using a coiled tubing setup or a well tractor conveyed tethered to a wireline. These deployment methods can have an effect on the flow regime during the logging survey. When oil company operations engineering teams require production log data across a flowing lateral, one aspect seldom addressed is how the deployment intervention can affect the well flow performance when deploying the production logging measurements. Often times the perturbation causing the well performance is based on the deployment intervention selection. This in return causes the well to underperform at the point in time a production logging survey is needed; leaving the logging technology with an unstable environment to deliver a confident result. What tends to occurs within the engineering teams is the perception that there is an inability of present day technology to accurately measure the well performance, meanwhile the deployment aspect chosen & the procedures to convey a production log actually can be a main culprit in changing the well flow dynamics & stability. Via deployment experience & a thorough understanding of well flow combined with production log analytical skill sets. This technical paper will discuss in a case history a production log run in a horizontal well, the deployment aspects & well flow challenges using wireline tractor & coiled tubing interventions, and how the end result was able to assist the customer.

The main objectives of this experimental study are to explore mechanisms controlling the onset of liquid loading and to investigate effect of well deviation on liquid loading. An experimental study of liquid loading of gas wells has been conducted with air/water flow in a 3-inch pipe at well deviations of 0°, 15° and 30° from vertical. A total of 131 tests have been carried out. Differential pressure gradient and liquid holdup were measured. Flow pattern was observed and videos were captured with a high speed video system. Critical gas velocity which defines the threshold for liquid accumulation in a well (commonly termed liquid loading) has been identified by analyzing different measurements including video captures. Results show different mechanisms for vertical and inclined pipe flows. A minimum pressure gradient criterion can be applied to determine the critical gas velocity. Well deviation angle has an effect on critical gas velocity. Performance analysis for various models has revealed their shortcomings.

Abstract Hydraulic fracturing process is an important stimulation technique that has been widely used in conventional and unconventional oil and gas reservoirs. The technique involves creation of fracture or fracture system in porous medium to overcome wellbore damage, to improve oil and gas productivity in low permeability reservoirs or to increase production in secondary recovery operations. This paper introduces a new technique for interpreting pressures behavior of a horizontal well with multiple hydraulic fractures. The well extends in multi-boundary reservoirs having different configurations. The hydraulic fractures in this model can be longitudinal or transverse, vertical or inclined, symmetrical or asymmetrical. The fractures are propagated in isotropic or anisotropic formations and considered having different dimensions and different spacing. The study has shown that pressure responses and flow regimes are significantly influenced by both reservoir's boundaries and fractures' dimensions. Different flow regimes have been observed for different conditions. New flow regimes have been introduced in this study. The first one is the early radial flow regime which represents the radial flow around each fracture in the vertical plane resulted due to the partial vertical penetration of hydraulic fractures. The second one is the second linear flow regime which represents the linear flow toward each fractures in the vertical plane normal to the wellbore resulted due to the long spacing between fractures. Third one is the third linear flow regime which represents the linear flow in the vertical plane parallel to the wellbore after the pressure pulse reaches the upper and lower impermeable boundaries.

Slickwater fracturing technology has been widely and successfully used for well stimulation because it is inexpensive and causes relatively little formation damage. Friction reducers are always employed in the slickwater fracturing fluid system due to the high friction pressures resulting from the high rates of fluid injection. Polyacrylamide-based polymer is the most common friction reducer in the industry. Many papers have reported the results of tests on friction reducers in water-based fluids in laboratory-scale straight and coiled tube, but few have attempted to address the gap between laboratory and field operation data. For example, laboratory tests using conventional fluid rheological parameters do not accurately predict friction reduction when applied to the large pipes used in field operations. Friction reducer evaluation using full-scale flow loop testing with tube sizes comparable to those used in field operations are typically expensive and require large volumes of fluids, making them impractical. This paper describes an attempt to address the gap between laboratory characterizations and field operations. It reports a study of two common friction reducers studied in a laboratory setup and compares the results with the recorded data from a large number of slickwater fracturing treatments over a wide range of pumping rates and well tube sizes. It introduces a new concept of effective pipe diameter, which, correlated with a fluid velocity profile, permits development of a model to reliably predict field friction reduction from laboratory results. The correlation between laboratory and field data is validated by comparing predictions with actual field data. The study demonstrates that correct lab testing parameters are essential for reliably using laboratory results to predict the effectiveness and performance of friction reducers under field conditions.

Well integrity management presents a wide variety of challenges for the industry today. With aging fields and more complex completion techniques coming into play, more efficient methods of well diagnostics and remediation are demanded. In the GOM, 45% of the wells have sustained casing pressure; therefore, the importance of having a resource that can provide an effective, accurate method of leak detection is abundantly clear. Typical methods of leak detection today include the use of spinners, temperature tools and noise logs. Mechanical means such as calipers and isolation packers are also employed. While effective for larger leaks, these methods can produce nebulous results with smaller leaks and can be time consuming. The frequency spectrum a leak produces is a function of differential pressure, leak magnitude, and leak geometry. These properties determine whether the frequency is audible, ultrasonic, or both. Typically, smaller volume leaks with a relatively high differential pressure will generate an ultrasonic signal. Based on this premise, an ultrasonic logging tool was developed and proven that detects frequency spectrums typically produced by leaks. The tool has a series of band pass filters which remove virtually all audible noise associated with tool movement, allowing continuous logging. Because ultrasonic energy will pass through compressed gas and steel, the tool can detect leaks in secondary barriers as well. Further, as ultrasonic energy attenuates quickly, the tool locates leaks with a high degree of accuracy. Using this tool, leaks as small as 0.005 gpm have been quickly located with an accuracy of a foot or less. This paper will describe a down-hole ultrasonic leak detection tool and provide case histories of where the ultrasonic leak detection tool was used to find leaks that other methods were unable to locate. A comparison of the results from conventional leak detection methods will be discussed as well.

Abstract Traditional US land hydrocarbon bearing shale formations are presently being drilled & produced via horizontal wells. These horizontal wells consist of numerous selectively shot stages containing as many as 15 stages spread out across 2000 ft to 5000 ft interval. These completions have been hydraulically fractured with water or slick water & require a flowback period of the injected water prior to the wells being kicked off with gas production. Since these types of formations are far from being homogeneous, the horizontal laterals can intersect existing natural fractures or faults in the formation or an aggressive hydraulic frac could induce fractures into existing natural fractures or faults. When producing horizontal wells the lateral section draw down of the formation water has the ability to enter the wellbore from these faults or fractures causing the well's gas production performance to drop & eventually die off. This paper will showcase US land horizontal well Production Logging deployment techniques using coiled tubing or well tractor examples & measurement techniques by imaging wellbore liquid / gas holdup, fluid velocity & thermal changes across the lateral. These techniques are successfully being used on US land horizontal wells in shale gas plays, whereby these case histories located inflowing gas and water entries across the lateral section. The emerging trend of drilling and completing long horizontal laterals in unconventional shale gas formations leads to novel deployment techniques and measurements in order to efficiently measure data across these producing lateral sections. Introduction Traditional US land hydrocarbon bearing shale formations are presently being drilled & produced via horizontal wells. These horizontal wells consist of numerous selectively shot stages containing as many as 15 stages spread out across 2000 ft to 5000 ft interval. These completions have been hydraulically fractured with water or slick water & require a flowback period of the injected water prior to the wells being kicked off with gas production. Since formations are far from being homogeneous, the horizontal laterals can intersect existing natural fractures or faults in the formation or an aggressive hydraulic frac could induce fractures into existing natural fractures or faults which can penetrate a lower water sand interval. US land shale gas producing wells are usually drilled to approximately 4,000 - 8,000 ft in depth & consist of a long radius dog leg and the producing lateral section extends out to 2,000 - 5,000 ft in length. These wells are normally competed with 4 ½" or 5 ½" casing and the lateral trajectory normally is drilled toe up (toe slightly above the heel, approximately 50 - 150 ft). These well are normally completed with 2 3/8" tubing with gas-lift mandrels installed to assist the water flow out of the heel section.

Abstract Cuttings transport in horizontal and highly deviated wellbores is challenging because the fluid velocity in these wells has a reduced vertical component. Hole cleaning sweeps are applied to reduce cuttings accumulation in the wellbore. Field studies indicate that fiber-containing sweep fluids have been very effective in cleaning horizontal and highly deviated wells. Although the results of preliminary field studies are encouraging, very little is currently known about cuttings transport efficiency of fiber sweeps. This article presents results of experimental investigations conducted to study hole cleaning performance of fiber sweeps. Flow loop experiments were performed in horizontal and inclined configurations using two test fluids: base fluid (0.47% Xanthan Gum); and fiber sweep (0.47% Xanthan Gum with 0.04% synthetic fiber). Rheological properties of the test fluids were very similar. Experiments were conducted by eroding cuttings deposited in the test section at a constant flow rate and measuring the amount of cuttings removed by the base and sweep fluids. Results indicate that the fiber sweep has better hole cleaning capabilities than the base fluid in the horizontal configuration. When tests were conducted in an inclined configuration (68° from vertical), improvement in the hole cleaning capability of the fluid due to the addition of fiber is moderate. The experimental results and findings of this research are very useful for directional and extended-reach well drilling applications. 1. Introduction Drilling of inclined and horizontal well often results in the accumulation of cuttings in the borehole. Excessive accumulation of cuttings is undesirable as it forms a thick bed that creates different drilling problems, such as higher equivalent circulation density (ECD), lost circulation, stuck pipe, and formation damage. Fluid circulation without drilling helps to reduce the thickness of the cuttings bed. However, in some cases, fluid circulation cannot clean the wellbore as desired and other techniques are considered. The use of drilling sweeps is one technique for removing cuttings beds that have not been cleaned by drilling fluid circulation. Regular drilling sweep application procedures require circulation of a certain volume of sweep fluid (i.e. different from the fluid used for drilling) at a given flow rate. Mostly these differences are in fluid viscosity (rheology) and/or density. As a result, conventional drilling fluid sweeps are classified into: high-viscosity sweeps; low viscosity sweeps; high-density sweeps; and tandem sweeps.

Abstract In some heavy oilfields, oil can flow in the reservoirs but may not flow through the wellbore without taking measures such as heating or diluting with light oil because of the high viscosity caused by low temperature around the wellbore close to surface. We focused on the latter issue in this study which is being widely used in Tah oilfield and other oilfields in China. Since the viscosity of the crude oil changes with temperature significantly, accurate prediction of wellbore temperature profiles is of great importance to determine the injection rate and temperature of light oil for dilution. An analytical model was derived to predict the wellbore temperature profiles for the heavy oil production assisted with the addition of light oil from the annulus. The model was based on energy balance between the formation and fluids flowing through each conduit. The temperature profiles were calculated using the proposed temperature model and the results were compared with the measured data. Sensitivity analysis was conducted using the proposed model and the main factors that influence the temperature profiles were discussed. Introduction Tah oilfield is one of the ultra-deep and ultra-heavy oil reservoirs in China. Most wells are deeper than 5000 m. Tah oilfield is also featured of high temperature (130oC) and high water salinity (over 100,000 ppm). Although the oil can flow in the reservoir easily (this may be because of the high reservoir temperature), it cannot flow to the surface in many wells. The main reason may be because the viscosity of the crude oil increases greatly in the upper part of the wellbore due to the low temperature around the wellbore at the shallow depth as a large amount of heat loses to the formation. In Tah oilfield, one of the solutions to this problem was to inject light oil with much lower viscosity through the annulus to the crude oil in the tubing. This approach has been being extensively applied in Tah oilfield and other oilfields in Xinjiang, China. Accurate prediction of the wellbore temperature profile is important to determining the values of the parameters (for example, the amount of light oil that should be added) in the design of the dilution projects because the oil viscosity varies significantly with temperature. There have been many papers on the calculation of the temperature profiles in the wellbore under different production conditions but few in the cases in which light oil is injected from the annulus to mix with the produced crude oil in the tubing. The physical process and heat-transfer in the case in which heavy oil is produced by adding light oil are similar to those in gas-lift wells. However there are some differences between the two cases. For example, the heat-transfer is of different characteristics for gas and light oil; the viscosity of the crude oil in the tubing is reduced significantly after mixing with the light oil injected from the annulus, which may affect the heat-transfer. Ramey (1962) might be the first to present a theoretical model to estimate fluid temperature as a function of well depth and production time. The model proposed by Ramey (1962) has been widely used in both geothermal and petroleum industries. However, the effects of kinetic energy and friction were ignored in the model proposed by Ramey (1962) and therefore the model is only applicable to single-phase flow. The approach reported by Satter (1965) improved Ramey's model by honoring the effect of phase change during steam injection. There have been many modified temperature models (Shiu and Beggs, 1980; Sagar, et al., 1991; Alves, et al., 1992; Hasan and Kabir, 1994 and 1996; Jurak and Prnic, 2005) for two-phase flow in wellbore since Ramey (1962) proposed the theoretical temperature model. Sagar et al. (1991) extended Ramey's model to multiphase flow in wellbore by considering kinetic energy and Joule-Thompson expansion effects. Hasan and Kabir (1996) reported a mechanistic model for circulating fluid temperature. Hasan et al. (1996) presented a model for gas-lifting wells.