Shut-in Time Research Articles

Numerical and Analytical Modelling of the Gas Well Liquid Loading Process

Summary Liquid loading is a serious problem in areas where gas fields are maturing. This paper presents an analysis of the production behavior of liquid-loaded wells over time. This clearly shows that these wells can operate at two different rates—a stable rate, at which full production is taking place, and at a lower metastable rate, at which liquid-loading effects play a role. A model has been constructed that enhances the understanding of the process of water buildup and drainage in gas wells. It assumes a single gas- and water-coproduction point and a single water reinjection point. As expected, a water column is built up in the well as soon as production takes place below the critical rate. As observed in the field, for good inflow performance, a metastable flow rate can be observed. At this state, the water-reinjection and water-coproduction rate are equal to one another, and the water-column height stabilizes. A sensitivity analysis has been carried out to determine how well parameters influence the metastable flow rate, the time required to reach this metastable rate, the corresponding water-column height, and the shut-in time required to drain this water column. The results of the analysis indicate that significant metastable flow rates occur in wells that have good inflow performance, a low water/gas ratio, and a large distance between injection and production point. Furthermore, a steady-state analytical solution has been derived for the metastable rate and stabilized water-column height confirming the numerical-analysis results. Introduction Many of the mature offshore gas fields in the southern North Sea have already experienced considerable pressure depletion resulting in significantly reduced gas flow rates and, eventually, liquid loading. Insight into the flow characteristics of these liquid-loaded wells will help manage tail-end production (i.e., will help define the most effective means of accelerating and maximizing their ultimate recovery.

Determination of formation temperatures from temperature logs in deep boreholes: comparison of three methods

The most important data on the thermal regime of the Earth's interior come from temperature measurements in deep boreholes. The drilling process greatly alters the temperature field of formations surrounding the wellbore. The temperature change is affected by many factors and the exact determination of formation temperature at any depth requires a certain length of shut-in time. In theory this shut-in time is infinitely long. There is, however, a practical limit to the time required for the difference in the temperature between the well wall and surrounding reservoir to become a negligible quantity. In this paper, we conducted a comparison of three methods of predicting the undisturbed formation temperatures from shut-in temperature logs in deep wells. Long-term temperature surveys in five wells were selected to estimate the formation temperatures and to compare measured and predicted transient formation temperatures. It was found that the best agreement is observed with values calculated by the ‘three-point method’ and measured during shut-in period transient temperatures.

Water-Based Insulating Fluids for Deepwater Riser Applications

Summary Uncontrolled heat transfer from production tubing to outer annulus—especially in deepwater riser sections—can cause the deposition of sludge, paraffin, and asphaltene materials; contribute to the formation of gas hydrates; and limit shut-in time for unplanned downtime or remedial operations. Generally, deepwater risers can be insulated externally or insulated by placing nitrogen gas into the riser annulus. In recent years, a new water-based thermal-insulating fluid system has been developed and used in field applications. This new system reduces convection and provides a rheological profile to facilitate fluid placement into the riser annulus. This system has been successfully used in deepwater risers in the Gulf of Mexico (GOM). Laboratory-scale equipment and a full-scale test well were constructed to evaluate the thermal-insulation properties of fluids. This paper details the testing procedures and methods. Steady-state heat-transfer- and cool-down-test results on the new insulation fluid were determined and compared to conventional fluids. These superinsulating fluids were found to be vastly superior to brine and measurably better than conventional water-based insulating fluids. Surprisingly, when compared to nitrogen (air) or argon, the superinsulating fluids provided enhanced protection during cool down. Field cases in the GOM are summarized to demonstrate the effectiveness of this fluid system.

Deepwater Well-Control Aspects for Slender-Well Drilling

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 94852, "Well-Control Aspects Regarding Slender-Well Drilling With Surface and Subsea BOPs," by C.S. Avelar, SPE, and S. Ohara, SPE, Shell Brasil; O.L.A. Santos, SPE, Petrobras; and P.R. Ribeiro, SPE, Unicamp, prepared for the 2005 SPE Latin American and Caribbean Petroleum Engineering Conference, Rio de Janeiro, 20-23 June. The 2003 Brazilian deepwater drilling record was achieved with a slender well in 9,475-ft water depth in Campos basin. The well was drilled safely with a surface-blowout-preventer (SBOP) system. The full-length paper details two discussions. The first is on technical issues concerning well-control operations on the drilled well and on a hypothetical conventional well. The second is on aspects of the SBOP technology. The main objective was to broaden discussion regarding application of the SBOP concept to explore and develop deepwater and ultradeepwater reserves in Brazil, with emphasis on well control. Introduction A combination of SBOP and a dynamically positioned (DP) semisubmersible drilling rig was used. The SBOP system included a surface-mounted BOP, a 13 3/8-in. high-pressure casing riser, a seabed shutoff and disconnect system (SDS), and control systems for these components. This SBOP system may be used with older-generation drilling rigs in ultradeep waters. Associated benefits can include reduced environmental damage because of the smaller volumes of drilling fluid and additives, compared with that used with a subsea-BOP system. The most important part of this work presents a comparison of a gas-kick circulation using the driller's method between the 9,475-ft-water-depth well drilled with an SBOP and a DP vessel and a hypothetical well drilled under the same conditions, but with the use of a subsea BOP. Well Scenario Fig. 1 shows the wellbore configurations for the two scenarios investigated in this paper. The system on the left shows a conventional situation having a 300-ton, 18 3/4-in. subsea BOP on the seabed with a 21-in. marine riser attached on top of it. The system on the right uses a 40-ton SBOP on top of a 13 3/8-in. high-pressure casing riser. The bottom of the casing riser is connected to the SDS at the seabed; the latter is used in case of an emergency disconnection. Below the mudline, both wells have the same design. Well-Control Simulation The well-control simulations were conducted with existing software that handles kick circulation by use of the driller's method. The theoretical basis involves a slug-flow model for the two-phase-flow region and a Bingham plastic model for the water-based mud. The bottomhole pressure was assumed constant and equal to the value of the formation pressure that generated the kick downhole, with a 50-psi safety margin added. Additional drilling parameters used in the simulations were as follows.Kick volumes: 5, 10, and 15 bbl.Shut-in drillpipe pressure: 650 psi.Flow rate: 450 gal/min.Shut-in time: 3 minutes.Reduced circulation rate: 100 gal/min.Surface temperature: 68°F.Temperature at mudline: 41°F.Bottomhole temperature: 234°F.Mud density: 10 lbm/gal.Mud rheology: shear stress=10 lbf/100 ft and viscosity=20 cp.

Pressure Transient Analysis in SAGD

Abstract Steam Assisted Gravity Drainage (SAGD) is an in situ thermal recovery technique used at Petro-Canada's MacKay River Project. The objective of this study is to develop an analytical well test method that would allow a measure of steam chamber volume and potentially the timing and location of steam chamber coalescence. This well test method would also prove useful in determining an analytical solution for near wellbore characteristics and reservoir boundaries. A pseudo-compositional thermal simulator was used to generate reservoir pressure responses by shutting off an injector at different periods of time and monitoring the pressure fall-off while continuing with production. Confined, unconfined, and coalesced 2-dimensional sink-source well pair models, based upon the geology and drilling pattern at Petro-Canada's MacKay River Project, were used in the study. The effect of the magnitude of the vertical permeability and the vertical to horizontal permeability ratio on the shut-in pressure response was also studied so that this method could be applied to other reservoirs of differing geology. Pressure response type curves were generated and the relationships between pressure drop at the injector, shut-in time, and steam chamber volume were determined. We show that the pressure response type curves are unique for different types of SAGD wells and levels of steam chamber development. This information will aid in determining the timing of operational conversions and determining recovery factors and possibly locations of reservoir boundaries, as well as steam chamber coalescence. Introduction In a commercial SAGD project, it can be expected that as the steam chambers mature and sweep through the reservoir, the well pairs will begin to interact with each other and the steam chambers will coalesce(1). Coalescence is defined as the point at which separate adjacent steam chambers merge to form one large steam chamber. Coalescence is used for timing operational conversions to secondary recovery schemes, such as solvent injection. As a result of the planning that is required for the operational conversion, a method of measuring the volume of the steam chamber would prove useful in estimating the timing of coalescence and the subsequent operational conversions. Considering there are 25 well pairs at MacKay River, it is also necessary to know which well pairs have coalesced so as to know the well pairs in which to institute operational conversions. For this reason, a well test method for determining which well pairs have coalesced is also required. The distance to and orientation of boundaries, flow regime, near wellbore characteristics (such as skin factor), and reservoir characteristics (such as effective permeability) can be determined through conventional pressure transient analysis. Conventional horizontal well testing has four different flow regimes that can be observed in the pressure response: early time radial flow, early time linear flow, pseudo steady state radial flow, and late time linear flow(2). The analytical solution is then applied in segments to the well test based upon the flow regime indicated by the pressure response. This segmental analysis can then be used to determine the reservoir characteristics.

Determination of formation temperature from bottom-hole temperature logs—a generalized Horner method

A new technique has been developed for the determination of the formation temperature from bottom-hole temperature logs. The adjusted circulation time concept, and a semi-analytical equation for the dimensionless temperature at the wall of an infinite long cylindrical source with a constant heat flow rate, is used to obtain the working formula. It is shown that the transient shut-in temperature is a function of the mud circulation and shut-in time, formation temperature, thermal diffusivity of formations and well radius. The sensitivity of the predicted values of formation temperature to the thermal diffusivity is shown. Two examples of calculations are presented.

Measurement of Acid Reaction Rates of a Deep Dolomitic Gas Reservoir

Abstract A rotating disk instrument was used to measure acid reaction rates, reaction order, and activation energy of reservoir rock from a deep dolomitic gas reservoir in Saudi Arabia. These values are required to optimize acidizing simulations. Results of more than 50 experiments are reported in this paper. Measurements were made from room temperature to 85 ° C at rotational speeds of 100 to 1,000 r/min and acid concentrations of 0.05 to 5 M HCl (0.2 to 17 wt%). The results show how acid dissolution rates change as the reservoir rock varied from 3 to 100 wt% dolomite. Factors affecting the measured parameters are discussed in detail. It was found that the reactivity of the rock varied from values expected for pure calcite marble to those expected for pure dolomite marble. At grain densities near 2.72 kg/dm3 (expected for pure calcite), rock dissolution rates varied by more than an order of magnitude, due to rock mineralogy. At grain densities near 2.83 kg/dm3 (expected for pure dolomite), rock dissolution rates were igher than that observed with pure dolomitic marble. Reaction rates depended on mineralogy and the presence of trace components such as clays. Introduction An accurate knowledge of acid reaction rates of deep gas reservoirs can contribute to the success of matrix and acid fracture treatments. These parameters are used in simulation models to estimate the optimum acid concentration, pumping rate, and shut-in time of acid treatments. Many studies of acid stimulation treatments of formation K, a deep, dolomitic gas reservoir in Saudi Arabia, have been published(1–3). This is the first study of acid reaction rates and reaction coefficients of this important formation. The rotating disk instrument is widely used in the petroleum industry for kinetic studies of the reaction of acidic fluids and chelating agents with reactive rock(4–10). This system allows the determination of rock dissolution rate, reaction rate constants, reaction order, and diffusion coefficients(4,11). In the rotating disk instrument, a rock disk 3.81 cm (1.5 in.) in diameter is mounted on a spindle using heat-shrink Teflon ® tubing. The rock disk can be spun at rates up to 1,000 r/min in a Hastelloy? B2 reaction vessel. Acid solution is preheated in a Hastelloy? B2 acid reservoir and transferred under pressure into the reaction vessel(4). Small volumes (8 mL) are removed from the reaction vessel every 2 minutes for 20 minutes. Concentrations of calcium and magnesium in the samples are determined by inductively coupled argon plasma emission spectroscopy. From the calcium and magnesium concentrations, and accounting for the loss of acid volume from the reactor, the amount of acid that reacted with the rock can be calculated for each sample(8). A plot of calculated acid concentrationvs. time shows the rate of acid consumption with time. From the slope of this line, and the surface area of the rock disk, the dissolution rate (moles/s cm2) can be calculated(6, 8). Test pressure was set at 6.9 MPa so that carbon dioxide would remain in solution.

水溶性ポリマー生産微生物を用いたＭＥＯＲの数値実験

Our group has carried out the various studies and experiments on MEOR process with the microbe producing water-soluble polymer. Based on these efforts, the basic performance and mechanism in this process were well simulated by computation experiment in the previous paper.In this paper, our group carried out the case studies of this process using the computation experiments and suggested the important conditions and its sensitivity of the effect.First, the effect of reservoir conditions was estimated by changing permeability distribution, oil viscosity and oil saturation. The ratio of the enhanced oil recovery by this process was high at the all conditions of reservoir. It should be noted that this process was effective in any types of reservoir without restrictions of permeability distribution, oil viscosity variety. It was shown that the application of this process in the earlier stage of development was more effective because oil recovery was accelerated in the earlier stage by increase of oil saturation.Next, the effect of cultivation conditions was estimated by changing nutrient concentration, shut-in time for incubation and fluid property. The ratio of the enhanced oil recovery became higher by increase of nutrient concentration, but they had not proportionality relation. Therefore, it is necessary to optimize nutrient concentration for target reservoir by estimating the economical efficiency. It was suggested that taking shut-in at least for 2 days was one of necessary procedure for higher enhanced oil recovery.Third, the effect of injection conditions was estimated by changing injection volume, rate of microbe, nutrient solution and injection cycle of the solution and water. It was shown that those conditions must be optimized by considering economical efficiency for target reservoir.In conclusion, it was suggested that the enhanced oil recovery by this MEOR process can be optimized by selecting suitable conditions to reservoir characteristics and by controlling conditions of cultivation and injection.

Halite Scale Formation in Gas-Producing Wells

In Northern German gas reservoirs, the precipitation of salt from the reservoir water is observed to an increasing extent as recovery progresses. The resulting halite scale causes a significant decrease in production rate, all the way to complete blockage of the flow paths and ultimately the abandonment of wells. In order to remove salt deposits as well as prevent the precipitation of salt in the zone immediately surrounding the well, fresh water treatments are performed at regular intervals during production operations. This paper addresses the entrainment of reservoir water from gas reservoirs, even in reservoirs without active edge-water drive, and the halite precipitation in depleted gas wells on the basis of theoretical considerations. The discussion includes a description of chemical parameters determined from analysis of reservoir water for the early detection of salt precipitates in the reservoir rock. Besides the implementation of the fresh water treatment in practice, special attention is paid to the dissolution behaviour of halite scale. The ionic distribution in the back-produced treatment fluid is evaluated with reference to the prevailing reservoir conditions. During the past 17 years, a large number of fresh water stimulations have been conducted in Northern German gas reservoirs. The results of these operations are explained in detail. The success of the stimulation based on the change in productivity index is evaluated and interpreted for parameters such as treatment volume and shut-in time.

The Effect of Fracturing Fluid Leak-Off on the Productivity of High Permeability Oil Reservoirs

Abstract During hydraulic fracturing of permeable reservoirs there is concern that fracturing fluid leak-off may cause a reduction in permeability. One important criterion of a successful fracturing treatment is limited formation damage. This study focused on investigating the alteration of permeability with distance from the fracture face, during fracturing fluid leak-off, and its subsequent recovery during production. Experiments were conducted in a 2-in. diameter and 12-in. long dynamic fluid loss core holder. Ten-in. long Berea sandstone core samples of varying permeabilities were used. Four different types of fracturing fluids were tested. Also, the effect of fluid loss additive on regain permeability was investigated. The movable oil phase in the core sample was either mineral or crude oil. The variation of return permeability with time and distance was determined along the length of the core sample. Effects of shut-in time, fluid loss additive, fracturing fluids, flow rates during flowback, and oil composition on regain permeability of oil reservoirs are presented in this paper. Introduction In recent years, tremendous interest has been developed in hydraulically fracturing high permeability formations(1–3). The objective is to improve production by creating propped fractures which aid in favorably altering the natural flow profiles. In order to optimize productivity, the fractures created should have a very high conductivity and the impairment in formation permeability due to fluid leak-off should be minimal. Fracturing fluids play a major role in the success of a fracturing treatment of high permeability formation. The fracturing fluid is expected to exhibit the following desirable properties:Cause minimum damage to formation permeability due to interaction of filtrate with the matrixGood proppant carrying capacityMinimum fracture conductivity damageFluid loss should be minimal In this paper, the emphasis is on the impact of fracturing fluid leak-off on the regain/return permeability of oil reservoirs. While fracturing a reservoir hydraulically, the fracturing fluid has a tendency to leak-off into the reservoir. The fluid which leaks off into the formation is generally called filtrate. The filtrate consists of polymer and/or particulates which can plug the pore throats, thereby reducing the near fracture face permeability. Usually, the leak-off is enormous in high permeability reservoirs, due to which there is a potential to drastically reduce the near fracture face permeability. This can lead to a reduction in productivity of the reservoir. Few researchers(4–6) have investigated the impairment in formation permeability caused by fracturing fluid leak-off in high permeability reservoirs. Further, all of the past studies were conducted in 100% brine saturated core samples. However, the formations that are hydraulically fractured contain movable oil and/or gas in addition to brine. It has been shown by Gadiyar et al.(7) that the presence of movable oil significantly alters the leak-off behavior of the fracturing fluids. Therefore, one would expect the return permeability and its recovery after leak-off in oil core to be different compared to that observed in 100% brine saturated core. The objective of this study is to investigate the effect of fracturing fluid leak-off on information permeability in the presence of movable oil saturation.

STATIC_TEMP: a useful computer code for calculating static formation temperatures in geothermal wells

The development and application of the computer code STATIC_TEMP, a useful tool for calculating static formation temperatures from actual bottomhole temperature data logged in geothermal wells is described. STATIC_TEMP is based on five analytical methods which are the most frequently used in the geothermal industry. Conductive and convective heat flow models (radial, spherical/radial and cylindrical/radial) were selected. The computer code is a useful tool that can be reliable used in situ to determine static formation temperatures before or during the completion stages of geothermal wells (drilling and cementing). Shut-in time and bottomhole temperature measurements logged during well completion activities are required as input data. Output results can include up to seven computations of the static formation temperature by each wellbore temperature data set analysed. STATIC_TEMP was written in Fortran-77 Microsoft language for MS-DOS environment using structured programming techniques. It runs on most IBM compatible personal computers. The source code and its computational architecture as well as the input and output files are described in detail. Validation and application examples on the use of this computer code with wellbore temperature data (obtained from specialised literature) and with actual bottomhole temperature data (taken from completion operations of some geothermal wells) are also presented.

Use of Temperature Simulations in Water-Control Design

Summary In this article we discuss a method to predict the temperature in the near-wellbore area during water shut-off treatments. It is essential to have a good estimate of the temperature because it greatly influences the success rate of a treatment. We present some new views on how treatment temperatures can be predicted accurately in order to design and execute a successful treatment. It explains how a production operation simulator can be used with an advanced-processes reservoir simulator to give an accurate estimate of the wellbore temperatures in the treated area. These data allow treatments to be designed on the basis of realistic temperatures rather than on bottomhole static temperatures. The results of the simulations can be used to optimize treatment placement rates, fluid composition, and shut-in times. Two case histories of recent jobs in the North Sea area are presented where simulations were used to design water-shut-off treatments and their placement. The first case illustrates how cooldown inside the reservoir was used to place a treatment that would otherwise have gelled spontaneously at the reservoir temperature. In the second case, temperature histories for different stages of the treatments were constructed from the simulation results. These temperature histories show that several different activator compositions and concentrations were required for the early, intermediate and final treatment stages.

Transient pressure of percolation through one dimension porous media with threshold pressure gradient

This paper studies the transient pressure of percolation during one production and one shutting in one dimension porous media with threshold pressure gradient, the differential equations are derived and solved with numerical computation. Basing on numerical solution, it is analyzed that: 1. the relation between the steady pressure at well bore (or at endpoint) and threshold pressure gradient, shut-in time, and the corresponding formulae are derived; 2. the regulation of transient pressure peak. The result is very useful and will help experiments and applications in the development of low permeability reservoirs with threshold pressure gradient.

Pressure buildup analysis of gas wells with damage and non-Darcy flow effect

This paper presents a technique to analyze pressure buildup test data of gas wells with damage and non-Darcy skin effect. This technique allows the analyst to estimate reservoir permeability and mechanical and rate-dependent skin factors directly by using 2 analysis plots. Formation permeability and rate-dependent skin are obtained from the slope and the intercept of the first plot, respectively, whereas the mechanical skin factor is determined from the intercept of the second plot. In addition, a graphical method to determine the reservoir pressure at infinite shut-in time is proposed. Field and simulated tests are presented to demonstrate the applicability of the technique. The results obtained are compared with new, conventional, and pressure derivative type curve matching techniques.

Using Interference Tests During Field Startup To Solve Critical Reservoir Management Issues at the Zafiro Field, Offshore Equatorial Guinea

Summary The Zafiro field, offshore Equatorial Guinea, was discovered in March 1995 by Mobil (75%) and partner United Meridian Corp. (25%). The field is being developed using subsea wells tied back to a floating production, storage, and offtake (FPSO) vessel. Field development used a fast-track process in which less than 18 months elapsed from discovery to the production of first oil. The Zafiro reservoir of the Zafiro field is highly stratigraphic in nature. Reservoir continuity was undefined before production. Seismic, geological, and pressure data gathered during an appraisal program of the main Zafiro field demonstrated the potential for discrete oil sands being in lateral and vertical communication. However, fluid samples indicated that the reservoir could be very compartmentalized. The implications of these two different models of reservoir continuity for reservoir development and, ultimately, reserves were profound. If the reservoir was very compartmentalized, development would require a significant number of wells, with the main recovery mechanism being solution gas drive. However, if the reservoir was reasonably continuous it could be developed using fewer wells, with pressure maintenance by water and gas injection yielding much higher reserves. To monitor reservoir performance, and to allow reservoir description by interference testing, permanently installed bottomhole-pressure gauges were run in all Zafiro wells during completion operations. These gauges were high-accuracy quartz gauges run on the tubing immediately above the reservoir. Gauge signals were transmitted to the subsea tree through cable strapped on the exterior of the production tubing, and then through a combined electrical and hydraulic control umbilical laid along the sea floor, connecting the subsea wells to the FPSO. A sophisticated data-monitoring and recording system was installed on the FPSO with the capability of recording data at a rate of one reading per second per well. An interference test was carried out during field startup to determine the degree of reservoir continuity within the field. This test involved producing a single well at a fixed rate while observing the reservoir pressure response in four offset wells. The test was designed using both analytical and numerical techniques, and included a clearly defined plan for sequencing well production to maximize reservoir data while minimizing well shut-in times. All bottomhole pressure gauges worked on startup. The interference test showed that all wells completed in the main Zafiro sands were in pressure communication. Strong lunar tidal effects were seen in all well responses. The investment of time and money in the installation of bottom-hole pressure gauges and interference testing during field startup allowed rapid acquisition of data critical to future reservoir management plans. Vital concerns over reservoir continuity were answered immediately, allowing implementation of fast-track plans for pressure maintenance to optimize oil recovery.

Geochemical results of a single-well hydraulic injection test in an experimental hot dry rock geothermal reservoir, Soultz-sous-Foreˆts, Alsace, France

As part of the investigation of the Hot Dry Rock (HDR) potential of the Soultz test site, 25 300 m 3 of fresh water were injected into borehole GPKI in granite between depths 2850 and 3400 m. The returned fluids were chemically monitored during the 57 h of production that followed the 21 h of shut-in time, and there is evidence of mixing and water-rock interactions. Although the chemical composition of the two sampled indigenous fluids (1817 m and 3485 m depth) which circulate at various levels in the granite is very similar, participation of both fluids in mixing with injected water has been revealed from the slight chemical differences. This test also suggests evidence for the presence of a third fluid. The large volume of injected water induced greater cooling of the reservoir than in previous tests, and a temperature effect on water-rock interactions has been demonstrated. There is release of Mg, and of SiO 2 and F to a lesser extent, whereas SO 4 release is greater because it is partly related to anhydrite dissolution. Mixing of the injected water with the highly saline indigenous fluid conceals part of the water-rock interactions because there is no evidence of the release of major elements (K, Na). However, trace elements are useful for determining some dissolution reactions, for example, relatively high concentrations of F and relatively low 87Sr/ 86Sr ratios. The presence of the brine also induces some chemical reactions as it increases calcite and anhydrite solubility. Lithium and B in the indigenous fluid are taken up during the test, and adsorption reactions on solid surfaces are proposed as an explanation for this depletion. Chemical monitoring during this single-well hydraulic test has proved relevant for determining which parts of the processes (dissolution and precipitation) are liable to modify the physical properties of the reservoir during fluid circulation for energy extraction, particularly in the vicinity of the injection borehole.

Interpretation of Fracture Height From Temperature Logs—The Effect of Wellbore/Fracture Separation

Summary Temperature logs commonly have been used to evaluate fracture height by locating cool anomalies that indicate the locations where cool fracture fluids were injected. Instead of cool anomalies, however, warm anomalies (called "warm noses") often occur on temperature logs run after fracture treatments. When interpreting fracture height from a temperature log, warm anomalies make it difficult to identify the top and bottom of the fracture. We believe that a plausible reason for warm anomalies is that the wellbore and the fracture are not coincident over the entire extent of the fracture; instead, away from the perforations, the fracture and the wellbore may be separated a finite distance that varies with depth. This paper investigates the effect of the existence and magnitude of the displacement between the wellbore and the fracture on wellbore temperature behavior after fracturing. The results obtained explain the "warm noses" on shut-in temperature logs run after a fracture treatment and, more generally, illustrate how fracture-wellbore separation can result in a variety of characteristic temperature log responses. A mathematical model has been developed to simulate the wellbore temperature after fracturing for cases where the wellbore and the fracture are not coincident for the entire extent of the fracture. The study shows that the temperature behavior strongly depends on the pattern and the magnitude of the displacement. When the fracture is perfectly connected with the wellbore, the cool region on the log indicates the top and bottom of the fracture clearly. However, the cool region is much smaller than the fracture height if the wellbore deviates from the fracture at a constant angle away from the perforations—a situation that may occur in a well that is deviated slightly from vertical, for example. Furthermore, "warm noses" appear on the log if the well spirals in a helical trajectory because the spacing between the wellbore and the fracture will vary with depth for this geometry. Therefore, when evaluating a postfracture temperature log, the possibility of a deviated wellbore-fracture system must be considered to avoid misinterpreting the fracture height. Longer shut-in times are shown to improve the fracture-height interpretation.

Material-Balance Calculations in Tight-Gas Reservoirs: The Pitfalls of p/z Plots and a More Accurate Technique

Summary Through the use of theoretical and field examples, the potentially large errors associated with use of straight-line p/z decline (tank) analysis to assess gas in place (GIP) and reserves in tight-gas reservoirs are illustrated. The basic tank assumption that reservoir pressure gradients are small can be violated, even with long shut-in times. It is also demonstrated that a reasonably-straight-line p/z decline does not necessarily indicate that the reservoir behaves as a tank. The communicating reservoir (CR) model is presented as a simple, yet much more accurate, method of performing materialbalance calculations in tight reservoirs. The results of the application of the CR model to the Waterton gas field are used to illustrate the success and large impact that can be obtained by examining the pressure behavior more closely than simply plotting p/z.

Cost-Effective Design of Scale-Inhibitor Squeeze Treatments Using a Mathematical Model

Summary Scale formation and deposition in production facilities is a challenging problem faced by the oil industry. Their deposition leads to operational problems, safety hazards, and an overall decrease in production efficiency. Downhole scale-inhibitor squeeze treatments provide the most common and effective means of preventing the formation of oilfield scale deposits. This paper presents an analysis and design study of field-inhibitor squeeze treatments. A mathematical model was used to simulate inhibitor-squeeze return data from several Saudi Aramco wells. A wide range of sensitivities in squeeze treatments were investigated, including inhibitor concentration, inhibitor volume, overflush size, and shut-in time. An optimization of the squeeze injection parameters was carried out with the numerical simulator. This optimization was based on squeeze performance as well as on economic criteria. The results indicate that the optimized treatment strategy is very well-specific and depends on the water production rates and operational parameters, like the scale-inhibitor concentration and volume and the amount of overflush. Recommendations are made for optimizing (in terms of cost effectiveness) the squeeze-treatment design.

A Novel Technology To Control Proppant Backproduction

Summary Backproduction of proppant from hydraulically fractured wells continues to create operational problems for oil and gas producers. As much as 20% of the proppant placed in the fracture can be returned to the surface, necessitating costly and labor-intensive surface-handling procedures. The development of unmanned platform operations remains impossible in some areas because of proppant backproduction. Flexibility in well turnaround and production strategies also can be very limited. Curable resin-coated proppant (RCP) has provided the most cost-effective and widely used method to control proppant backproduction. While this is a valuable technique that has served the industry well for many years, it is not universally successful. A new technology has been developed to control proppant back-production and to increase flexibility in well turnaround and production strategies. The technology has been used successfully on several hundred hydraulic fracturing treatments. In this technology, a mixture of fibers and proppant is pumped into the fracture to form a pack that is resistant to proppant backproduction under typical oil/gas production conditions. The proppant/fiber mixture depends on a physical mechanism rather than chemical bonding to increase pack resistance to flowback. There are no minimum closure stress, temperature, or shut-in time requirements associated with the use of this technology, which increases the flexibility available to the operator to optimize well turnaround and production strategy. This paper reviews the laboratory data relevant to the understanding and application of this technology. Studies include proppant pack resistance to flowback in one- and two-phase flow, the effect of cyclic loading, aging phenomena, permeability/conductivity studies, and fluid/breaker interactions. The benefits of the technology are illustrated with field studies.