Conventional horizontal well transient response models are generally based on the line source approximation of the partially penetrating vertical fracture solution.These models have three major limitations: (i) wellbore pressure is computed at a finite radius outside the source; it is impossible to compute wellbore pressure within the source, (ii) it is difficult to conduct a realistic comparison between horizontal well and vertical fracture productivities, because wellbore pressures are not computed at the same point, and (iii) the line source approximation may not be adequate for reservoirs with thin pay zones. This work attempts to overcome these limitations by developing a more flexible analytical solution using the solid bar approximation. A technique that permits the conversion of the pressure response of any horizontal well system into a physically equivalent vertical fracture response is also presented.
A new type curve solution is developed for a horizontal well producing from a solid bar source in an infinite-acting reservoir by means of Newman's product solution. Analysis of computed wellbore pressures reveals that error ranging from 5 to 20% was introduced by the line source assumption depending on the value of dimensionless radius (rwD). Computations show that for rwD = 10-4 the transient response of a horizontal well is identical to that of a partially penetrating vertical fracture system, and for rwD > 0.01 the transient response of a horizontal well is indistinguishable from that of a horizontal fracture system. Type-curve plots for the ranges 0.01 = dimensionless length (LD) = 10, and 10-4 = rwD = 1.0 are presented.
A dimensionless rate function ( ß-function) is introduced to convert the transient-response of a horizontal well into an equivalent vertical fracture response. A step-wise algorithm for the computation ofß-function is developed using Duhamel's principle. This provides an easier way of representing horizontal wells in numerical reservoir simulation without the rigor of employing complex formulations for the computation of effective well block radius.
The United States Natural Gas Market has moved through some very dynamic events over the past few years.The fact that ninety-eight percent of all gas consumed in the US comes from the North American Continent plays a large part in the lack of stability in pricing of Natural Gas.The nature of the production stream feeding the demand for gas has changed drastically in the past decade.The potential demand for gas during peak usage periods of each year has changed dramatically and the maturity of the available gas development projects have all led to a greatly different market than ten years ago.
This paper will update the status of the US Gas market; the state of US production, the change in demand for gas as prices change, estimations for the potential expansion of gas supply and the need for imported gas from outside of the North American continent.
In recent years, a technique of separating water downhole to reduce the volume of produced water and decrease the chance of surface pollution has been developed. It is called downhole oil-water separation (DOWS) technology. This technique allows water to be separated in the wellbore and injected into a suitable injection zone downhole while oil with traces of water is produced to the surface.
Subsequent to the introduction of the DOWS technology to the oil industry in the 1990's, several trial applications have been undertaken to test the technology. These trials allowed significant information to be collected on the feasibility of the DOWS technology. Through the joint efforts of Argonne National Laboratory, CH2M-Hill, and the Nebraska Oil and Gas Conservation Commission, a comprehensive technical report was issued in January 1999 discussing this technology. Additional reports on trial applications and feasibility studies have been presented by various study groups.
This paper reviews the status of and issues surrounding the application of downhole separation technology. This review summarizes the various papers and reports dealing with DOWS technology and its application in the oil and gas industry. This technology has the potential to provide significant reductions in produced water as the technology is adopted by the industry. It can also reduce produced water handling costs and increase oil and gas production in the right application. The wide-spread adoption of DOWS technology is dependent on improving the understanding of the process and its applications throughout the oil and gas industry.
Flow through annulus is frequent in drilling and work-over operations. Annular flow is also utilized in some fracturing treatments. In all these applications, Newtonian and non-Newtonian fluids are widely used. Therefore the knowledge of annular flow performance of these fluids becomes important for planning and design of well-bore hydraulics. Existing knowledge about the behavior of non-Newtonian fluids in annulus is very limited due to their complex behaviour. A range of correlations is available in the literature for both Newtonian and non-Newtonian fluids in laminar and turbulent flow regime. Selection of the appropriate correlation for the desired fluid and flow regime is very important for the accurate determination of friction losses.
Experimental and simulation study has been undertaken to investigate the flow behavior and friction pressure losses of Newtonian and non-Newtonian fluids in concentric annuli. Computational Fluid Dynamics (CFD) has been used along with limited experimentation on a field-scale set up to validate the simulation results. The fluids investigated are water and frequently used concentrations of guar and Xanthan fluids. CFD simulations have been performed for different annular dimensions in flow range encompassing both the laminar and turbulent flow regimes. The annular dimensions used in the simulations cover the range used in the industry. The frictional losses of non-Newtonian fluids exhibiting drag-reducing characteristics have been investigated through experiments.
Based on the comparison with simulation results recom¬mendations are made to use the appropriate correlations for Newtonian and non-Newtonian fluids in the laminar and turbulent flow regime.Improved correlations are proposed to determine frictional losses of non-Newtonian fluids exhibiting drag-reducing characteristics. These correlations are based on experimental data gathered for a wide range of concentrations of guar and Xanthan fluids. The recommendations made along with the correlations presented in this study will greatly improve the accuracy of determining friction pressure losses in concentric annuli.
Polymer gels used for shutting off unwanted water in producing oil wells are certainly no stranger to the Arbuckle dolomite formation in Kansas, but in years past, they have delivered short-lived results and have been only marginally successful.In November 1997, that all changed after a unique design strategy utilizing proven polymer gel technology caused dramatic increases in oil production that resulted from shutting off a significant volume of water from a well located in the Bemis-Shutts field.Since that time, more than 200 wells have been treated for about 35 different operators with a greater than 95% success rate. Thousands of barrels of incremental oil at each treated well are being realized, and hundreds of thousands to millions of barrels less water are being produced from each treated well, than otherwise would have been produced without the treatment.These treatments are extending, by several years, the economic life of many Arbuckle wells, and are bringing shut-in wells back to life.
This paper will report lessons learned from applying polymer gel water shut off technology to the Arbuckle formation, and present statistical data derived from a detailed database that has been maintained throughout the project.In addition to using the database as a tool to quantify results and further improve job performance, it is also being used to improve the predictability of response to treatment.Post-treatment oil and water production performance and treatment longevity will be compared to several variables like polymer gel treatment volume and injection pressure.The paper will also discuss how polymer injectivity and post-treatment well performance changes from place to place within the Arbuckle formation.Finally, treatment economics including job cost, payout time, revenue gain from increased oil and decreased water production, and return on investment will be presented.
Improved matrix-fracture interface fluid transfer functions for naturally fractured reservoirs are formulated and the associated parameters are determined by experimental data. Hindered-fluid transfer across the matrix-fracture interface due to skin effect is considered. Applications for single phase oil or gas production by pressure depression and oil production by immiscible displacement are accomplished by means of dimensionless phenomenological equations. Analytical solutions are derived for special boundary conditions involving the typical laboratory tests and reservoir simulation to represent the various matrix block shapes. The present analytical solutions involve the skin effect, anisotropic porous matrix, properly scaled variables, and full-time solutions and asymptotic solutions for early- and late-time periods. These solutions are obtained after proper linearization of the porous matrix fluid transfer model for one-, two-, and three-dimensional Cartesian matrix blocks, circular-cylinder and annular shaped matrix blocks, and spherical matrix blocks. The characteristic parameters of the transfer functions, namely the diffusion coefficient, skin coefficient, and skin thickness, are determined by conforming special analytical solutions to experimental data involving fluid exchange between matrix and fracture by imbibition.
The rising portion of plunger cycle makes use of some type of designed sealing mechanisms on the plunger. These sealing techniques reduce the amount of gas that bypasses (leakage) the surfacing plungers. When falling, many plungers have mechanisms designed to allow increased leakage or slippage enabling the plungers to fall faster.
Modeling techniques, for leakage about a rising plunger, shown in this paper are shown as analogous to orifice type flow restriction. For fast falling plungers the model is developed is similar to objects experiencing drag in a field of gas velocity. Data collected for this type of modeling is presented from suspension tests and confirmed with dynamic test data. Model ratification is done with some dynamic test data. Special two-piece and conventional plungers are hereby modeled from suspension and dynamic testing.
The results should help the operators to select specific plunger hardware for specific conditions and should assist in modeling plunger cycles.
Plunger lift is a common artificial lift method of producing liquids from a gas well to improve gas flow, usually without the addition of any outside energy or extra gas. The need for plunger lift arises as the reservoir pressure decreases and lower gas velocity fails to lift liquid from the well. The objective of plunger lift is to keep the wellbore free of liquids and associated pressure drop by lifting liquids on an intermittent basis to the surface. The feasibility of plunger lift is widely discussed in the literature[1-5].
This paper chiefly will deal with modeling and predicted results for plunger rise, plunger fall and also the lifting of liquid slugs over the plunger. The direct outcome of these results is to help assist the operators on the plunger hardware to be selected and in the set-up of the duration of the plunger cycles.
Gas slips upward around the plunger when it rises in the wellbore during the plunger cycle. The percentage of leakage5 compared to the gas production is relatively small. This leakage can gradually reduce the pressure under the plunger and reduce lifting energy if too much gas slips past. However, conventionally the plunger is designed with sealing contours or mechanisms to prevent the gas from underneath the plunger to leak to the liquid slug above it. Considered here also, is the modeling of the two-piece plunger and the conventional ‘sealing mechanism' used with plungers for the rising and falling portion of the plunger cycle. In addition, modeling for lifting of the liquid slug is also provided showing how effects of the liquid slug size can affect the average rise velocity of the plunger along with other parameters. The details can be found in the following sub sections. These new considerations in modeling help provide a better understanding, of plunger cycles and operation. Data obtained from experimental runs from a test site was input into the model developed. The experimental data was obtained by suspension and dynamic testing. The results from the models were in the approximate range of measured data, thus validating the model.
Two-Piece Plunger. The plunger consists of a hollow cylindrical piston and a ball below. The hollow cylindrical piston could be changed in length, material used, thickness, size and number of grooves depending upon usage but is usually a fixed configuration with various materials available. The two-piece plunger cycle[5,6] typically requires about 5 to 10 seconds of shut-in time and the well is producing even when the plunger components are falling to the bottom of the tubing. The model developed is presented in Appendix A.
Fig. D-1 shows the various types of two-piece plungers currently being used in the industry and Fig. D-2 shows the mechanical components. The shifting rod seen in Fig. D-2 generally has a taper to it with large diameter towards the bottom of the rod. This helps facilitate holding the hollow cylinder at the top while the well is producing.
Depletion of the reservoirs in the San Juan Basin is causing production rates to drop below the minimum lift critical velocity (MCV) in a large number of wells.Traditional methods used to address this issue include plunger lift, pumping units, foam lift, and re-circulation for wells with a compressor and tubing.With declining reservoir pressures, both plunger lift and re-circulation become less effective and often times the expense of a pumping unit, both to purchase and operate, cannot be economically supported by the well.In some cases, injecting surfactant may offer the most cost effective method of removing fluids.
To date, foam lift operations in the San Juan Basin have been accomplished by two methods.The most common method of applying surfactant to a well is dropping "soap sticks."This is very inexpensive but it demands a large amount of time from field personnel and can yield inconsistent production rates.The other common method of delivering surfactant to the well is through continuous injection of surfactant at the wellhead.The major problem with this method is that surfactant must drip down the annulus or tubing, which limits its effectiveness due to plating out on the wall surface.
The problems described above are eliminated through the use of a Downhole Capillary Surfactant Injection System (DCSIS).The DCSIS delivers surfactant directly to the bottom of the well bore where it is needed to be effective.A capillary stainless steel tubing string is run in the well bore and is attached to a fluid pump and a chemical storage tank.The capillary string can be run inside the tubing, outside the tubing, or down the slim hole production casing.Once installed, a metered amount of surfactant is injected down hole to help unload the well.
This paper discusses the results of a 10-well pilot of the DCSIS in the San Juan Basin.The pilot's objective was to determine the physical parameters necessary to estimate the MCV for foam flow and establish better criteria for selecting future installations.To accomplish these objectives, it was necessary to analyze the positive and negative responses to the installation of the DCSIS and determine the factors that led to each response.The data was then analyzed using statistical modeling tools to determine the most important factors affecting the response variable, percent increase in production (% uplift).This paper will discuss the results of a regression model that was built to determine the significance of several factors and to aid in the candidate selection process for future installations.Practical methods of determining the physical parameters necessary to generate foam flow will also be presented.
A high-pressure, high-temperature (HPHT) bubble chamber apparatus is used to determine carbon dioxide (CO2) foam stability, interfacial tension (IFT) between HPHT CO2 and surfactant solutions and critical micelle concentration (CMC). Chaser CD1045™ (CD) was used in this study. In this study, changes of temperature from 25 to 75ºC, pressure from 800 to 2000 psig, and surfactant concentration from 0.005 wt% to 1 wt% were tested for foam stability, IFT and CMC. The relationship of foam stability and IFT is also discussed in this paper.
IFT decreased with surfactant concentration below the CMC and was essentially constant above the CMC, increasing with the increase of temperature and the decrease of pressure. Stability of CO2-foam is surfactant concentration-dependent. The coalescence of bubbles was observed only at CD concentration of 0.005 wt%, well below the CMC at 25ºC and 1500 psig. The foam was stable under all tested temperatures at surfactant concentrations of 0.1 wt% and above, and decreased with increase of temperature at surfactant concentrations of 0.05 wt% and below at 1500 psig. The foam was stable under all tested pressure at surfactant concentrations of 0.025 wt% and above, and decreased with increase of pressure at CD concentrations of 0.005 wt% at 25ºC, and similar behaviors were observed at high CD concentrations at 75ºC.
CO2 flooding is generally considered the fastest-growing improved oil recovery (IOR) technique. In 2002 the number of reported CO2 projects in the United States exceeded the number of thermal projects for the first time. This is due to recent research focusing on CO2 flooding, availability of CO2, reservoirs amenable to CO2 flooding, and success of CO2 floods. On the basis of laboratory displacement experiments and field applications, at pressures above the minimum miscibility pressure of CO2 and reservoir oil, a developed miscibility flood could be expected to produce a significant fraction of the oil remaining in the formation.[2-14] CO2 flooding can increase oil recovery by 7-15% of the original oil in place and can be sustained for 10-30 years.[2-14] The use of CO2 flooding for IOR is increasing, because of the following reasons:
CO2 remains a dense fluid over much of the range of pressures and temperatures found in many oil reservoirs.
CO2 fluid is miscible or partial miscible with many hydrocarbon components of crude oil at reservoir conditions.
Dense CO2 has relatively low solubility in water compared to oil.
The U.S has CO2 resources near many oil fields.
As a displacement fluid, CO2 costs are relatively low if the CO2 is found near an oil field.
Environmental and economic benefits are derived from related CO2 sequestration and the worldwide potential increases for CO2 use in IOR.
This paper was also presented as SPE 94156, "Does Vogel's IPR Work for Fractured Wells?" at the 2005 SPE Europec/EAGE Annual Conference held 13-16 June, in Madrid, Spain.
It is a common practice in the oil industry that production engineers use Vogel's correlation to correct the IPR curve below the bubble pressure for unfractured and fractured wells. However, there has not been a comprehensive investigation to ensure if the Vogel's correlation can be applied for fractured wells.
This paper presents a new correlation to build IPR curves or predict production performance below the bubble pressure for fractured wells. In order to investigate fractured well performance below bubble point, about 1,000 simulations runs were performed using well-refined size grid for several sets of relative permeability curves and PVT data. The simulation model has been validated against analytical solution. Those runs cover a big practical range of fracture penetration 0.1 to 1.0 and dimensionless fracture conductivities from 0.5 to 50. Steady state conditions were analyzed at this study.All the mechanisms that cause the difference between fractured well and radial flow performance below the bubble pressure has been also well studied and will be presented in this paper.
It was found that Vogel's correlation underestimates fractured well performance below bubble point. Vogel suggests a correction of AOF by 45% meanwhile the simulation results and new correlation show that the correction should be only 22%. Therefore, engineer could have an error of 43% using Vogel for estimating AOF for a fractured well.
Another finding of this study is that multiphase effect is dependent on fracture conductivity and almost independent on fracture penetration. Higher conductivity fractures has bigger gas banks therefore they are affected by multi-phase effect to greater extent than lower conductivity ones. The new correlation is now being used for different fields and better fits the data than Vogel's correlation.