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.
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 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.
Removal of hydrogen sulfide from natural gas is a primary concern for many producers.Many natural gas systems throughout the South Texas area have H2S concentrations that range from less than 10 ppm to more than 1000 ppm.While amine units are usually efficient at removing H2S cost-effectively, the high capital cost has encouraged the development of other treatment methodologies for the removal of low to moderate quantities of H2S from natural gas.One such method is the injection of liquid chemical scavengers directly into the gas stream.The chemical scavenger reacts with the H2S and forms a product that is removed from the gas by separation equipment, such as a scrubber.
Although the chemistries of the scavenger reactions are fairly well known, the efficiency and therefore the cost-effectiveness of removing H2S by this method is highly dependent on system conditions and architecture.Many parameters impact the efficiency of liquid H2S scavenger application.Important factors include mixing, a function of several parameters such as gas velocity and injection method, and retention time, which is the time available at a specific set of conditions to achieve maximum scavenger efficiency.Based on these and other factors, a field study was undertaken to evaluate the effects of system conditions, architecture modifications, and of specialized equipment types on improving the efficiency of H2S removal.This paper will present field data and describe the mass balance efficiencies of several types of scavenger applications including injection into existing systems, the use of retention treating loops, and bubble towers for the removal of H2S.
The use of mass balance calculations during the project allowed for careful assessment of scavenger efficiencies in a variety of conditions and treatment scenarios.Mass balance is a useful tool when liquid scavenger testing includes several formulations of varying concentrations.The results of the field evaluation provided data that led to a better understanding of liquid scavenger usage and applications limits.The improved understanding of treatment envelopes allows field users to more efficiently identify candidate scavenger processes and make more informed decisions on process selection for removal of H2S from natural gas streams.
The ever increasing operator demands and objectives to mill fast and efficient windows has led to the development of innovative milling technology. New lead mill profiles and cutting structures have replaced old crushed carbide technology.The new design utilizes inserts brazed into pockets machined in the mill head. Mills dressed with the new cutting structure are able to effectively mill a casing window and drill formation rat hole in less time than it took with the welded-on crushed carbide technology.
With this new design, operators are now afforded an option. In medium to hard formations, the new cutting structure can be used to mill the window and drill rat hole in one trip. While sidetracking in formations with high compressive strengths, Polycrystalline Diamond Compact (PDC) inserts can be utilized. The use of the new cutting structure in a one trip sidetrack system can result in substantial cost savings, improved milling reliability and a higher quality window.
The combination of new cutting elements and mill profile has proved to be economically sound allowing for consistency of product manufacturing and has eliminated the potential variances inherent in the welding processes. The system design and cutting structure reduces torsional resistance providing for smoother in-gauged milled windows in one trip.
This paper updates an earlier paper with the concepts of using the new cutting structure and presents the new technology and recent case histories of four sidetrack operations.
In order to supply operator demands for milling windows faster and more efficient, a commitment was made by an oil service company to develop new technology and sharing this new technology within the corporate business units. The sharing of technology has led to innovative drilling technology to be used in milling full-size casing windows at a lower cost. The working together of the diamond manufacture business unit, the PDC bit business unit, and the remedial services business unit has proven to be very advantageous in the advancement of diamond technology and mill head design.
The use of multiple axis milling machines has led to precise and consistent manufacture of the Lead Mill profile and cutting structure.The mill profile and cutting structure are responsible for cutting the window in casing and for drilling formation. The cylindrically shaped inserts are brazed into pockets milled into the mill cutting structure.The technique used to braze the inserts into the pockets has proved to be reliable and has greatly reduced the damaging effects caused from excessive heat from the welder's torch.
Changing the Lead Mill cutting structure from the crushed tungsten carbide and/or pre-formed tungsten carbide to the cylindrically shaped insert cutting structure has had a profound impact in the Lead Mill performance and reliability.
Advancements in Lead Mill profile design, diamond technology, and cutting structure density has led to the development of the Hard Formation Mill. As more sidetracks were performed in formations with compressive strengths of greater then 20,000 psi, the need for a sidetrack mill that can cut a window in casing and drill formation in one trip was apparent.
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.
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.
Drilled wellbores have evolved from nearly vertical, shallow holes to tortuous, deep, directionally drilled wells. As wellbore geometries have increased in complexity, so has the potential of damage resulting from casing wear. It is not unusual to routinely install ditch magnets in the returned drilling fluid circuit to catch the iron filings created by tool joint wear against the casing or riser interior wall.
While most "straight" holes attempt to control inclination, azimuth control is often times neglected, potentially creating a tortuous path. In directionally drilled holes, including horizontal and multi-lateral wells, the drill string tension holds the rotating tool joints against the inner wall of the casing for extended periods. This results in the generation of crescent shaped wear grooves (key seating) in the inner wall of the casing, often dangerously weakening casing or riser strings making them more susceptible to burst or collapse.
Some investigators have sought to quantify this damage process. Computer models describe, measure, and predict damage from casing or riser wear. From these on-going studies, advances in technology continue to minimize casing and riser wear.
More than 475 8-hour casing and riser wear tests have been conducted, producing the largest casing/riser wear database known. Analysis of this database led to the development of the contact pressure threshold concept, consistently demonstrating its validity.
When a rotating tool joint impinges against the inner wall of a casing or riser, a crescent shaped groove is worn into the inner wall. The volume worn away from the casing or riser wall is proportional to the frictional work done on the inner wall by the tool joint. This is mathematically presented in the equation:
Experimentally determined over an 8-hour testing period, the Casing Wear Factor, WF, is then defined as the ratio of friction factor to specific energy, as shown in equation 2,
and the sliding distance is defined as shown in equation 3,
If the length of a joint of drill pipe is Ldp, and the length of a tool joint is Ltj, then
As an example: If Ldp = 30 ft., and Ltj = 14 inches, f = 0.039.
Thus, the volume of casing wall removed per foot in time t hours is given by equation 5.
To establish a benchmark test for comparison of casing wear factors, a set of standard dimensions and conditions for conducting the wear testing was established. These dimensions and conditions are shown in Table 1.
Since discussions of the testing program and the significance of the measured wear characteristics are presented in other publications, they will not be repeated here.
The amount of polymer damage created by a fracturing system has been a problem for many years.Polymer damage results in the reduction of fracture conductivity and effective propped fracture length.One method to reduce polymer damage is to reduce gel loadings.Historically systems that were developed to reduce polymer loadings have encountered numerous problems.The limiting factor for reducing the amount of polymer in a fracturing system is the point where the viscosity of the fluid is not adequate to transport proppant.In areas of low permeability gas wells, poor proppant transport results in less than desired production due to decreased fracture length in the reservoir.
Many of these low-polymer fracturing systems are not operationally feasible due to the lack of a suitable water source for the system to yield its peak viscosity.In addition to the operational issues of locating a suitable water source, another constraint on some of these systems is the requirement to use a liquid KCl substitute in place of granular KCl.These issues have limited the use of the low-polymer systems in many areas.The shear sensitivity associated with the use of organometallic crosslinkers is a problem encountered by many low-polymer systems.High tubular velocities will shear degrade the fluid reducing it's proppant transport capability compared to that of a borate crosslinked system.
This paper will discuss a modification to a well-established borate crosslinked fluid and system that eliminates these problems.Case histories will be given for the applications and results of this reduced polymer system that yields comparable viscosities to higher polymer loading systems.
In the Central US, recent application of new PDC cutter technology throughout the drilling of more than 40 wells has produced an impressive step change in drilling efficiency. The step change is clearly demonstrated by real time cost savings and a significant reduction in drilling times.
To date, more than 240,000 oil and 59,000 gas wells have been drilled in the Central US in the State of Oklahoma alone. In an attempt to improve drilling economics and reduce operational risks in the region, operators and bit manufacturers have been working as a team to develop PDC drill bits that can drill faster and deeper into harder, complex geological formations with high compressive strengths and abrasive properties. In addition, the longer runs achievable by fixed cutter PDC bits reduce the risks involved in running roller cone designs and the likelihood of problems during trips in and out of the hole. With this goal in mind, many different bit types with developmental PDC cutters recently have been run in the Central US region.
Drilling performance showed significant improvement when a drill bit design modification was introduced that replaced existing cutters with a newly developed PDC cutter designated Z3™. Introduction of the new cutter, the only bit design parameter that was changed, resulted in consistent performance improvements in penetration rate and footage drilled in applications throughout the region. For example, in South Central Oklahoma, a PDC bit design with the new cutters improved penetration rates to as high as 175ft/hr, where existing PDC bit designs averaged 90-100 ft/hr. In Western Oklahoma, a bit with the new cutters drilled more than 800 feet deeper than offsets, the first bit in the area to drill the entire section to TD. In the Texas Panhandle, the bit designs consistently improved footage performance in the hard formation applications.
This paper describes a new cutter technology which offers significantly greater abrasion resistance as well as resistance to thermal mechanical failure than have previous cutters. This paper also discusses various cases studies from the US Central area that show the performance improvements resulting from use of the new cutters. An economic analysis demonstrates the cost savings realized.