High-pressure Wells Research Articles

Wellhead Innovations for Hot High-Pressure Wells

Summary Mobil Oil Indonesia's (MOI's) Arun wells produce gas A rates up to 150 MMscf/D (4.25 × 10 6 M 3 /d). The gas contains 14 % CO2, and up to 100 ppm H2S. The Rowing wellhead temperature is about 325deg. F (163deg.C). The original shut-in surface pressure was 5,800 psi (40 MPa). Failure of the resilient wellhead casing seals occurred in about 40% of the wells. This was attributed primarily to the effects of high flowing wellhead primarily to the effects of high flowing wellhead temperatures and to temperature cycling between flowing and shut-in conditions. MOI decided that a metal to metal seal, between the 9%-in. (24.5-cm) casing long string and wellhead, was required to ensure a long-term effective wellhead seal for Arun producing conditions. Wellhead metal-to-metal seals of the size and type required for 9 5/8%-in. (24.5-cm) casing did not exist anywhere in the industry. We worked with the manufacturers of the wellheads used in Arun who designed, tested, and manufactured metal-to-metal wellhead seals. Special tools were developed to field-machine the casing so that an effective metal-to-metal seal is obtained between the casing and the wellhead. Arun Field Arun field is one of the largest gas fields in the world. It is in the rice-growing area of North Sumatra about 8.7 miles (14 km) from the coast (Fig. 1). The field was discovered by MOI in 1971 in the Bee Block Contract Area in Aceh Province, North Sumatra. The structure is about 11.5 miles long and 3. 1 miles wide (18 1/2 km long and 5 km wide) wide a productive area of about 23,400 acres (94.7 × 10 6 M 2 ). The reservoir is a carbonate reef. The top of the reef averages about 9,800 ft (2990 m) subsea. Both the original reservoir pressure of 7,100 psi (49 MPa) and the reservoir temperature of 352deg. F (178deg.C) are abnormally high. The hydrocarbon well stream contains 13.8 mol% CO2, 5.9 mol% water, 50 to 100 ppm H2S, and traces of mercury. About 45 to 50 bbl/MMscf (0.00028 m 3 /std M3) of condensate are produced with the gas. produced with the gas. Producing wells, production facilities, and compression facilities are placed in clusters where the produced fluids are cooled, dehydrated, and separated (Fig. 2). Excess produced gas is compressed and injected into a number of downdip injection wells. Gas and condensate flow through separate pipelines to Pertamina's liquefied natural gas (LNG) plant on the Pertamina's liquefied natural gas (LNG) plant on the coast near Lho Seumawe for processing, liquefaction, and export. Design of Arun Wells The Arun formation is a thick, highly productive carbonate reef. To take advantage of this productivity, 7-in. (17.8-cm) tubing was chosen. A diagram of the original producing wells is shown in Fig. 3. The casing strings of producing wells is shown in Fig. 3. The casing strings of 20-, 13%-, and 9%-in. (50.8-, 34.0-, and 24.5-cm) are run and cemented to the surface. Original Design of Arun Wellheads (Fig. 4) The Arun well producing conditions are among the most severe in the world. The original reservoir pressure was 7,100 psi (49 N4Pa) at an average depth of 10,000 ft (3050 m), and the reservoir temperature is 352deg. F (178deg.C). The wells are designed to produce at rates of 150 to 175 MMscf/D (4.25 × 106 M3 /d to 5.0x 106 M3/d) with 45 to 50bbl/MMscf 0.00028 M3 /std M3) Of condensate. The original surface wellhead pressures were 5,800 psi (40 MPa) shut-in and 4,900 psi (34 MPa) flowing. The surface temperatures range from 100deg.F (38deg. C) when the well is shut in, to 325deg. F (163deg. C) when the well is flowing, to 80deg. F (27deg. C) when the well is being treated. JPT p. 284

Drilling high-pressure wells in cameroon : Du Charlat, A; Rioche, D; Suchon, C Oil gas J, V80, N18, 3 May 1982, P183–199

Drilling high-pressure wells in cameroon : Du Charlat, A; Rioche, D; Suchon, C Oil gas J, V80, N18, 3 May 1982, P183–199

Contingency Planning for Drilling and Producing High-Pressure Sour-Gas Wells

A blowout of a sour-gas well near a populated area can expose local residents to hazards that are not normally associated with a blowout of an oil or gas well. Without detailed plans made well in advance and kept current, such an accident can have serious consequences for a company that is not prepared. Introduction Field experience in developing the sour-gas reserves discovered in Western Canada in the early 1950's showed that metals often failed quickly when exposed to sour gas because of its hydrogen sulfide (H2S) content. For a time there was considerable concern about the industry's ability to provide facilities that could safely handle this gas, but research by both industry and universities developed the necessary technology, and today sour-gas production and processing in this area is a safe, routine operation. This achievement can be attributed, for the most part, to the careful selection, quality control, and inspection of materials scheduled for use in sour-gas service. Now once again the industry is faced with a new challenge for producing sour gas. Drilling for and producing from deep, high-pressured reservoirs of producing from deep, high-pressured reservoirs of high H2S content present a hazard not normally associated with the production of sour gas from moderately pressured reservoirs. This is the threat of blowouts caused by the often rapid failure of high-strength steels when they are exposed to hydrogen sulfide. When H2S is Present, the yield strength of steel must be limited to about 90 to 100 ksi and stringent quality control and inspection procedures must be set up to insure that higher strength materials are not used to drill or complete the well. In spite of all possible precautions, there will always exist the possibility that failure of some component during the possibility that failure of some component during the lifetime of a well may lead to a blowout with disastrous results. When a blowout occurs in an ultra-deep well, much time may be required to control it if relief wells must be drilled. Thus if the well does not bridge or the reservoir does not deplete quickly, the operator will be faced with protecting the lives and property of nearby residents for an extended period. This is particularly serious when the period. This is particularly serious when the blowout occurs near a heavily populated area. We shall discuss here various elements that Shell considered in developing contingency plans for its deep Smackover drilling program in Mississippi. The actual plans are quite detailed and outline the responsibilities and duties of all concerned, from top management to the field operations personnel. They are divided into two parts, one dealing with procedures for protecting the operating personnel, and the other outlining means for protecting nearby residents and their property. The execution of the latter is primarily the responsibility of the staff organization; primarily the responsibility of the staff organization; however, the field operating personnel are responsible for the production of any endangered residents until the staff group relieves them of this function. The plans are principally designed to cope with the period of shock that immediately follows an accident, when there is the greatest danger of losing control of the situation. General Considerations Contingency plans must be specific in assigning duties and areas of responsibility, so that each man knows what is expected of him during an emergency. JPT P. 347

Stimulation of the Deep Ellenburger in the Delaware Basin

Certain problems are inherent in stimulating deep, hot wells. Experience with wells in the Delaware Basin has led to this paper, which explains how such problems as the following have been dealt with: (1) inability to confine the treatment within the desired interval; (2) lack of fracture-fluid-loss control; (3) lack of definite knowledge regarding acid reaction and flow mechanisms at high temperatures and pressures; and (4) limitations that are dictated by dry gas reservoirs and that are not present in oil wells. Since some standard techniques and most standard chemicals were not usable, new methods and materials have been developed and are described. (15 refs.)

Gas Well Testing With Turbulence, Damage and Wellbore Storage

Abstract A systematic study has been made of the application of the real gas pseudo-pressure m(p) to short-time gas well testing. The m(p) function can be used in real gas flow problems to account for the variation of viscosity and z-factor with pressure. A mathematical model was solved numerically to generate solutions of various real gas flow problems. The erects of turbulence, formation damage and wellbore storage were included in the model. The analysis of simulated well tests showed that the interpretation methods normally used for liquid flow are generally accurate when the m(p) is used. For practical rates without turbulence, the solutions are not rate-sensitive, and the flow capacity kh and skin effect can be determined accurately from either a buildup or a drawdown test. However, the kh calculated from a drawdown test can be significantly low when turbulence is present. A case was simulated in which this error was 36 percent. Turbulence does not affect the determination of kh from buildup tests. The proper determination of kh from p and p2 buildup and drawdown plots is developed by analyzing their relationship to the m(p) method. A simple equation is given that can be used for long-range gas well performance forecasting. This expression is compared with a method presented by Russell et al. Introduction The formation flow capacity and wellbore damage condition can be determined for liquid-producing tests by means of buildup and drawdown tests. These tests make use of short-time pressure transient data rather than stabilized flow tests that are often used for gas well testing. Tracy presented a method of gas well testing that was based on ideal gas equations and utilized p buildup plots. This method was shown to be good for low pressure wells. Matthews suggested plotting p and using an average slope and average gas properties. This method was more successful on high pressure wells. Al-Hussainy, Ramey and Crawford showed that variation in gas properties could be simplified by using the real gas pseudo-pressure m(p). Some cases showed that the use of the m(p) function provided an accurate method of interpreting buildup and drawdown tests. Because the work of Al-Hussainy et al. included only a few actual cases, there was a need to explore the use of the m(p) method for a greater variety of flow conditions. The occurrence of turbulent flow around the wellbore often is an important factor in gas well testing. Swift and Kiel, and Carter et al. treated turbulence in gas well testing, but did not consider the variation of viscosity and z-factor with pressure. This paper presents the results of an investigation of the application of the m(p) method to buildup and drawdown testing. The investigation included the effects of turbulence, formation damage and wellbore storage. Gas Flow Equations To formulate the mathematical model, many of the assumptions usually used in well testing theory are applied. The system has radial geometry with a closed outer boundary and is composed of a horizontal porous formation that has uniform and isotropic rock properties and uniform thickness. Allowance is made, however, for a radial region of reduced permeability near the wellbore. This region represents formation damage. The geometry of the system is shown in Fig. 1. Darcy's law does not always apply to gas flow. JPT P. 877ˆ

Magnetic Tape Recorders for Down-hole Data Recovery and Their Use with Electronic Tubing Calipers

Abstract A magnetic tape recorder has been developed for the storage and recovery of data of subsurface instruments. This 14-channel recorder is capable of storing data from 14 independent transducers and may be lowered through production tubing on a solid wireline. The recording technique, the response of the recorder and the temperature limitations of the recorder are briefly described in this paper. A magnetic tubing caliper developed for use with this recorder is also presented. Finally, description of the experimental calipering system used to indicate mental loss in tubing on the surface, as well as the principle of operation of this magnetic caliper when used for subsurface operations, is included. Introduction Techniques for recovery of data from oil wells are highly developed and widely practiced. The more intricate techniques usually employ a conductor cable to transmit information to the surface in the form of electrical signals from a transducer which has been lowered into the borehole. Special equipment is required to lower instruments attached to a conductor cable into high-pressure wells. At very high pressures this may not be effective or, at very best, is quite costly. Expensive electronic equipment is required at the wellsite to receive, store and prepare the data for interpretation.A down-hole data-recovery system which contains smaller and often less-complicated subsurface equipment and which is easy to run in producing wells is offered by a magnetic tape recorder with self-contained battery power. Data can be recovered and stored without any electrical communication between the transducer and the surface. A self-contained unit can be lowered into high-pressure wells by means of a solid wireline without special techniques and equipment. The down-hole electronics needed for preparing information for recording is comparable to and, in most cases, less complex than that required to recover the same data by means of an electrical conductor line. No additional electronic equipment which must be operated by competent technicians is needed at the wellsite.A magnetic tape recorder for down-hole data recovery has been tested under field conditions simulated in the laboratory. This multi-channel recorder is capable of recording information from 14 independent sources simultaneously, and can be lowered into production tubing with a nominal ID of 2-in. or larger. Magnetic Tape Recording All magnetic tape recording is accomplished by subjecting the ferromagnetic material on the tape to a magnetic field. Particles on the tape become magnetized and retain some of the magnetization after the magnetic field has been removed. Magnetic fields are produced by current in the coils of the record head, and the tape is subjected to these fields by passing the tape over the recording head so that it encounters the flux fringing from the head gap.The playback head of a recording system, which utilizes motion between the head and medium to produce the flux changes and reproduces the signal, is identical or similar in construction to the record head. The voltage induced in the coil of the playback head with sinusoidal residual magnetism on the tape is given by the formula . . . . . . . . (1) where k = a constant of proportionality including the number of coil turns on the head and amplitude of the residual magnetism on the medium, f = frequency of the sinusoidal wave, and t = time. Thus, the output signal is proportional to the amplitude and frequency of the recorded signal. Doubling the reproduced frequency by doubling the velocity of the medium will produce the same increased output as doubling the recording frequency, assuming the recording signal is constant in amplitude. Eq. 1 assumed that the gap in the head was short compared to the wave length of the signal. JPT P. 137^

Some Problems of Superhigh-Pressure Gas Reservoirs In the Gulf Coast Area

Introduction As the search for oil and gas has progressed to deeper horizons, problems of abnormally high pressures have become increasingly difficult. Several of the world's oil- and gas-producing areas have extremely high pressures, and one of the most notable of these is the area about 50-miles wide along the coast of the Gulf of Mexico from the Rio Grande to the Mississippi delta. Hundreds of wells along the Louisiana coast have pressures greater than normal (gradient of .465 psi/ft of depth), and it is from this area that the data presented in this article were obtained. In earlier days completions in reservoirs with abnormally high pressures were unsuccessful for the most part, and the consensus then was that such reservoirs were small and, therefore, uneconomical. There was some basis for this belief, for until recently more money had been spent in discovering and developing high-pressure formations than the value of the oil and gas found. Operators tried deeper drilling, by which they hoped to drill past the high-pressure zones to other normal-pressure formations more favorable for the production of hydrocarbons. Once an abnormal-pressure zone is encountered, all deeper formations, as a rule, have abnormally high pressures; thus, the idea of finding normal-pressure reservoirs under high-pressure zones did not work out. At the same time, many big and valuable accumulations of hydrocarbons have been discovered in the high-pressure zones. After it was found that high pressures did not necessarily mean poor recoveries, it became apparent that drilling (though no less serious) was not the only problem. New problems of completion, production and reservoir performance, which did not occur in normal-pressure reservoirs, must be faced and solved. The way these new problems are handled will have much to do with the value of these high-pressure reserves. Drilling Excellent reports on the occurrence of abnormally high-pressure reservoirs have been made by Cannon and Craze, Cannon and Sullins, Watts, and Dickinson. The most credible theory of the cause of abnormally high pressures is that the formations cannot bear the overburden without compaction, and that they are effectively isolated from any other porous and permeable formation which contains normal hydrostatic pressure. Dickinson found that most of the abnormal-pressure reservoirs in south Louisiana are below the base of the main sand development because conditions favorable for isolation are seldom found within the main sand series. Therefore, a knowledge of the depth at which the change in facies from predominantly sand to predominantly shale occurs is an indication of the depth at which abnormally high pressures may be encountered. It follows then that, if the pressure to be encountered can be predicted fairly accurately, many drilling problems can be overcome. Drilling problems are magnified as the amount of uncased hole increases. Shallower formations often are unable to withstand the weight of the mud column needed to control the pressure of the deeper zones and will break down, causing a loss of returns. This quickly creates an imbalance between formation pressure and the pressure exerted by the mud column, and can result in a blowout. For years operators have wrestled with this problem of lost returns, but proper programming of drilling activities. such as the selection of casing setting depths, has brought success in drilling abnormally high-pressure wells. Some knowledge of how pressures are increasing with depth aids materially in deciding where to set protective casing. It does not necessarily follow, though, that the best depth was selected just because someone successfully drilled a well by setting pipe at that depth. Some very interesting facts relating to the increase of abnormal pressures with depth came to light during the development of the Lake Arthur field in Jefferson Davis Parish, La. The south half of the Lake Arthur field, which is the portion of abnormal pressures, has a productive area of some 7,000 acres (Fig. 1) and had original recoverable reserves in excess of 2 trillion cu ft of gas. In the area of abnormal pressures 40 wells have been completed, and there are 17 abnormal-pressure reservoirs in eight horizons, ranging in depth from 8,500 to below 15,000 ft. Surface pressures have been as high as 11,900 psi, and reservoir pressures have been computed to be in excess of 14,000 psi. JPT P. 935^

Applications of a Subsurface Solid-State Isotope Injector To Nuclear-Tracer Survey Methods

Abstract The techniques of following the movement of dispensed isotopes in a wellbore with a gamma-ray detector have been described in previous literature. The method of determining fluid-movement profiles and velocity readings in wellbores has proved valuable for defining producing zones and thief zones, for water flooding for secondary recovery programs and for solving lost-circulation problems. The Electric isotope injector utilizes a new principle to eliminate many of the disadvantages of previous down-hole dispensers. This method injects radioisotope from a solid state directly into the surrounding fluid. The radioactivity is "fixed" on a metal "button" carried by the tool; when ready to perform an injection operation, the button is lowered to the appropriate depth in the well. The isotope is dispensed from the button by energizing the proper circuits in the logging system from the control panel in the logging service truck. The isotope remains in stable solution in the well fluid. The injector is run in combination with the Scintillometer gamma-ray logging tool for tracing the movement of the fluid. Using isotopes in solid-state form is a major improvement from the standpoint of radiation safety. The problems of radioactive-material spillage and contamination have been virtually eliminated. This new tool has been field-tested under high-temperature and high-pressure well conditions and has proved very reliable and dependable under various well conditions. The substantial saving in operating time and the more reliable control permitted provides an economical and efficient subsurface tracer-survey system. Introduction Numerous techniques have been developed in the literature regarding the dispensing and tracing of radioisotopes in subsurface operations. The solution of problems relating to the detection of fluid movement in the well and subsequently into subsurface strata can become complex by using radioisotopes as tracer material. Probably the earliest application of radioactive materials in oilfield operations was the addition of carnotite to cement slurry and the subsequent detecting of the height of the cement column through location of the gamma-ray emissions. Possibly the most important and widely developed use of radioisotopes has taken place in injectivity-profile studies. The success of injection and permeability profiles in waterflood operations has been amply demonstrated for a number of years. Oil- or water-injection profiles, made both before and after fracturing operations, are extremely beneficial in demonstrating the efficiency of fracture treatments. Additional applications for tracer surveys have been developed for locating lost-circulation zones in drilling operations, locating casing leaks, locating cement-channeling behind casing and for determining the effects of vertical permeability on fluid movement through a reservoir. Techniques have been developed and utilized for almost any application in which the detection of fluid movement is essential for sound drilling or production practices. Prior to the development of the Electric Isotope Injector, utilization of radioisotopes in either oil- or water-soluble states necessitated injecting the liquid tracer either at the wellhead or from a container lowered on a cable into the wellbore. This type of downhole dispenser depended entirely upon electro-mechanical and/or hydraulic action to evacuate the isotope from the container. Injecting radioisotopes through wellhead equipment demands a high degree of control in handling procedures, in preventing surface radioactive contamination, and in monitoring practices. Operations with older down-hole dispensers have been plagued by a number of serious problems, including radioactive-material leakage at undesired depths and the failure of tools to operate at high temperatures and high pressures. To overcome many of these problems, the McCullough Tool Co. designed and has successfully utilized the Electric Isotope Injector. JPT P. 121^

Simultaneous Flow of Gas and Liquid As Encountered in Well Tubing

Abstract The paper deals with pressure gradients occurring in flowing and gas-lift wells, a knowledge of which can be applied to the determination of optimum flow-string dimensions and to the design of gas-lift installations. The study is based on a pressure-balance equation for the pressure gradient. It appears that a pressure-gradient correlation of general validity must essentially consist of two parts-one part being a correlation for liquid hold-up and the other part being one for wall friction. Dimensional analysis indicates that both liquid hold-up and wall friction are related to nine dimensionless groups. It is shown that in the field of interest only four groups are really important. On the basis of these four groups a restricted experimental program could be selected that nevertheless covered practically all conditions encountered in oil wells. This experimental program has been carried out in a laboratory installation. Three essentially different flow regimes were found. The pressure gradients in these regions are presented in the form of a set of correlations. Comparison of these correlations with a few available oilfield data showed excellent agreement. Introduction Prediction of the pressure drop in the flow string of a well is a widely known problem in oilfield practice. Accurate data on the pressure gradient of a simultaneous flow of gas and liquid in a vertical pipe are especially useful for the determination of optimum flowstring dimensions. It is well known that with moderate gas and liquid flows such a vertical string acts as a "negative restriction". The pressure drop decreaseswhen the throughput through a given pipe increases, andwhen at a given throughput the cross-sectional area is decreased. The reason is that, with increasing velocities, the flow becomes more agitated so that the gas slips relatively more slowly through the liquid. With the resulting increase in gas content in the string, the static head decreases. When the area becomes very small, however, the high velocities entail great wall friction, which causes an increase in pressure drop. For a given flow, therefore, minimal pressure drop is obtained by using a certain cross section. This means that, in principle, each well can be provided with an optimum flow string for minimum pressure drop and, hence, maximum possible production rate. The procedure for the selection of the optimum string has been discussed by Gilbert. A necessary tool in the procedure, however, is accurate knowledge of the pressure gradient to be expected for various values of the governing variables. Another application of pressure-gradient data lies in the field of gas-lift practice: they provide a means of determining the optimum gas-injection rate, optimum injection pressure and optimum injection depth. Much work has already been done in the study of the pressure gradient of vertical gas-liquid flow. Poettmann and Carpenter presented a pressure-gradient correlation based on measurements in wells. This correlation has been found to provide accurate predictions in high-pressure wells and in high-production wells for flow through both tubing and annuli. However, when their method is checked on low pressure-low production wells or on wells with viscous crudes, serious discrepancies are found. As we shall see in the next section, this is due to the fact that their correlation factor, representing all irreversible energy losses, is given as a function of only one correlation group. Some important variables, such as gas-liquid ratio and liquid viscosity, are not incorporated in this group so that their specific effects are not accounted for. To study also the mechanism of vertical gas-liquid flow outside the ranges covered by the Poettmann-Carpenter publication and extensions, a laboratory investigation has been carried out. This study is founded on a pressure-gradient equation that is based on a pressure balance. To reduce the number of test runs required, a dimensional analysis has been carried out, followed by a selection of relevant dimensionless groups. These groups guided a subsequent experimental study, and with their aid the experimental program could be minimized while still covering the majority of the situations encountered in oilfield practice. In this paper the choice of a formula for the pressure gradient is discussed first. This is followed by a brief description of the experimental setup. Subsequently, the dimensional analysis is discussed and the relevant dimensionless groups are selected, resulting in the experimental program required.

The Calculation of Pressure Drop in the Flow of Natural Gas Through Pipe

Abstract An equation has been derived for use in calculating the sandface pressure of flowing gas wells in which the variation of the compressibility factor of the gas with pressure is taken into consideration. This variation due to compressibility has been put into both graphical and tabular form. Comparison of calculated results with field measured results were made on 20 dry gas wells from a given field and 11 distillate wells from different fields. The agreement between calculated and observed results is good. In addition to their use in the calculation of sand face pressures of flowing wells, the factors can be used in the direct calculation of the static bottom hole pressure of gas wells, the capacity of gas transmission lines, and in the calculation of the theoretical isothermal horsepower necessary to compress a natural gas. Examples demonstrating the use of various equations are given. Introduction Many of the equations used to calculate the sand face pressures of flowing gas wells from well head data do not take into consideration rigorously the deviation of the natural gas from ideal gas behavior. For low pressure wells this error is not serious. For high pressure wells flowing at high rates this error can be serious. Sandface pressures are used to determine the producing capacity of gas wells as shown in the U. S. Bureau of Mines Monograph 7. An equation has been derived for use in calculating the sand face pressure of flowing gas wells in which the variation of compressibility of the gas with pressure is taken into consideration. This variation due to compressibility has been put into both graphical and tabular form. In addition to their use in the calculation of sandface pressures, these "factors" can also be used to give a direct solution in the calculation of the static bottom hole pressure of gas wells, the calculation of the capacity of gas transmission lines, and the calculation of the isothermal horsepower necessary to compress a gas.

Corrosion in Condensate And in High Pressure Sweet Oil Wells

The problem of corrosion in condensate and high pressure wells producing sweet oil is discussed. The corrosion problem encountered in condensate wells is rather well known, but it is not generally ...

Selective Adsorption of Hydrocarbon and Water Vapor on Alumina at Atmospheric Pressure

Abstract The simultaneous adsorption of water and hydrocarbon vapor from natural gas bythree grades of alumina has been studied at atmospheric pressure andtemperature. Results of this investigation reveal that the presence of watervapor in the gas inhibits the adsorption of hydrocarbon vapor, although thepresence of the latter does not have a pronounced effect upon the adsorption ofwater vapor. Adsorption of water-hydrocarbon mixtures from gas is divided intothree phases. In the first, both water and hydrocarbon vapor are adsorbed; inthe second, adsorption of water vapor proceeds while desorption of hydrocarbontakes place; in-the third phase, the adsorbent approaches complete saturationwith respect to both water and hydrocarbon vapors. Both theory and experimentaldata can be applied to design and operation of commercial dehydration plants, and an illustration is presented. Introduction Dehydration of natural gas becomes increasingly important as the operatingpressures employed in gas processing and transmission are increased above 500lb. per sq. in. Gas produced from high-pressure wells is saturated with watervapor when it leaves the reservoir and it continues into the processing plantor transmission system in a saturated condition because of the substantialdecrease in temperature due to expansion at the wellhead. Usually this gas isaccompanied by liquid water and hydrocarbons that have condensed with thechange in temperature and pressure. Without dehydration, gas temperatures must be held at relatively high levels toprevent solidification of gas hydrates. According to Hammerschmidt's data onthe relationship of pressure to the freezing point of natural-gas hydrates, theminimum safe operating temperatures range from 55? to 90?F for pressuresranging from 500 to 3000 lb. per sq. in., respectively. Often it is difficultto maintain gas temperatures above the hydrate-freezing temperature because ofclimatic conditions, unless flow-line heaters are installed. Also, inprocessing gas for its gasoline content at high pressures, it is desirable toemploy operating temperatures lower than the hydrate-freezing point. Indistributing high-pressure gas, the large pressure drop from line pressure totown-gate pressure often produces sufficient cooling to freeze the regulatorsand disrupt consumer service. Therefore, it is highly essential to dehydratehigh-pressure natural gas if smooth and economical operation is to bemaintained at all times. Few published data are available on the simultaneous adsorption of water andhydrocarbon vapors. T.P. 1628

Methods of Tubing High-pressure Wells

During the past year or two considerable time and money have been spent indeveloping equipment for tubing large-volume high-pressure oil and gas wellswithout loss of production. That the efforts have met with success is proved bythe fact that any properly cased well, regardless of its production orregardless of its rock pressure or working pressure, can now be safely tubedwith no appreciable loss of production, provided experienced crews handle thenew equipment. It is conceded that a far better gas-oil ratio can be secured by flowing a wellthrough tubing of a proper diameter-the diameter of the tubing depending, ofcourse, upon the volume of fluid and gas and the depth of the well-than by themore usual method of installing a choke at the mouth of the well. Wherepossible it is becoming the practice to bring wells in through tubing, thoughin the majority of instances this is not feasible. In many instances it hasdeveloped, after a well has been brought in through tubing that the tubinginstalled is either too large or too small for the most efficient operation orthat the well had not been drilled deep enough. The equipment described in this paper, in the hands of experienced men, permitsthe tubing of these wells after they have been brought in, with the size oftubing then determined by actual observation to be best suited for eachparticular well, and with no danger of the well getting out of control, ofcatching fire, of drilling itself deeper, or of any loss of production. Thedeeper the flowing production with the consequent future higher lifting costs, the more essential it is that the size of tubing used be such as to give thebest possible gas-oil ratio. The ability to bring in these deep wells throughthe casing and then, immediately after their completion, regardless of volumeor pressure, to tube them with the size of tubing that permits the mostefficient use of the gas present will doubtless save many dollars.

Anti-Gas Channeling Technology with Gas-Block Plug for High Temperature and High Pressure Wells in the Periphery of the Tahe Oilfield

Excessive gas channeling velocity is a big challenge in the Ordovician high-temperature and high-pressure(HTHP)reservoirs along the periphery of the Tahe Oilfield,Xinjiang.To solve this problem,an analysis was conducted on the mechanisms and influencing factors of oil/gas migration.The study concluded that the main factors affecting the oil/gas migration were the gel strength and the surface tension of fluids in the wellbore.Hence,researchers developed an anti-gas channeling technology with gas-block plug.In this process,researchers selected key treatment agents for gas blocking,such as high temperature rheological modifier SMRM,surface tension modifier SMSM and high temperature fluid loss additive SMPFL.Thus it was possible to match high temperature resistant gas-block plug regimes and processes.The gas-block plug is resistant temperature as high as 200℃,while the surface tension was lower than 22 mN/m.When the gel strength was higher than 30 Pa at high temperature,there was a good level of compatibility with the mud in the wellbore.The anti-gas channeling technology were applied in 5 wells with severe gas invasion in periphery of the Tahe Oilfield.The techniques were then respectively matched with the operations like drilling,logging,coring and completion.The application results showed that the gas channeling velocity was reduced by more than 75%,the safety operation period was extended,and the drilling safety and efficiency were improved.The successful development and application of high temperature resistant gas-block plug could provide a safe and effective well control measure for the drilling and completion of gas invasion HTHP reservoirs.