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A wellhead choke controls the surface pressure and production rate from a well. Chokes usually are selected so that fluctuations in the line pressure downstream of the choke have no effect on the production rate. This requires that flow through the choke be at critical flow conditions. Under critical flow conditions, the flow rate is a function of the upstream or tubing pressure only. For this condition to occur, the downstream pressure must be approximately 0.55 or less of the tubing pressure.
Abstract Production allocation is of utmost importance for optimum reservoir development and production optimization. The need for quality oil, water and gas rate allocation has been increasing for determining the hydrocarbon delivery history for each well. The allocation becomes more complex when no periodic well test, no reservoir pressure recorded during pump shut in period, Malfunction of the pump sensors (Intake Pump pressure (Pi), Discharge Pump pressure (Pd)), Chock sizes per each well are not recorded with time, no surface gas/oil rate measurements or even the majority of well tests were conducted in commingle mode. This paper presents an iterative methodology for oil and gas rate allocation. It combines the inflow performance relationship and vertical lift performance with real time wellhead data to create the flow model for each well. Furthermore, by combining the down-hole sensor data from ESP pump with Gilbert choke equation using the upstream and downstream pressures, accurate oil and gas rate allocation can be predicted. This methodology provides the hydrocarbon delivery of the well to give the chance for production optimization. This methodology was applied on a field case from western desert in Egypt for oil and gas production rate allocation and it is verified against sporadic well test points
Inflows of gas into the primary cement slurry column of wells in the Ten Section field of Kern County have severely damaged the cement integrity. An inexpensive cement slurry and process design has been implemented that minimizes gas flows into the cement and eliminates the need of expensive remedial squeeze work.
A. Problem Description
Gas invasion of a setting primary cement slurry is a very destructive process that results in a loss of good formation hydraulic isolation and expensive completions.
A great deal of gas migration research has been undertaken recently. Numerous publications define the mechanisms at work in a setting cement column that can allow gas intrusion.
Carter and Slagle recognized gas cutting effects on cement in 1972. They suggested that the cement column cannot effectively transmit full hydrostatic pressure to the zone containing the gas. They proposed that certain characteristics of the cement column (density, setting, gelatin, dehydration, and bridging) could all contribute to gas influx. They concluded that the following design criteria are critical for the prevention of gas migration: (1) maintaining a hydrostatic head that exceeds formation gas pressure, (2) preventing cement filtrate loss with appropriate fluid-loss controls, (3) pipe movement while cementing, (4) and proper casing centralization. These were considered the most critical elements of preventing gas leakage.
C. E. Cooke et al. supported these theories with the placement of pressure and temperature sensors outside the casing at various depths. All information from the sensors was recorded as cement was placed behind pipe in various wells. With the analysis of the data from these experiments, they confirmed that the pressure at various depths in a cement column begins to decline shortly after the pumping of the cement is completed. The pressure loss, they postulated, can be explained in terms of a volume reduction of the cement and sufficient gel strength of the cement to prevent downward movement of the column.
A complete cement system design that limited annular gas flow problems was introduced by Hartog et al. in 1983. They emphasized the importance of understanding the mechanisms causing a loss of hydrostatic head and included a cement design that stressed certain cementing techniques that could limit gas migration, such as: (1) drilling an on-gauge hole, (2) conditioning mud, (3) removing mudcake, (4) use of spacers, (5) use of highly-thinned scavenger cements, (6) low fluid loss, (7) good cement velocities, (8) a set minimum contact time, (9) pipe reciprocation, and (10) good casing centralization. They concluded that good cement designs based on these criteria would decrease the likelihood of gas intrusion and poor cement bonding.
In further investigation, Cheung and Beirute concluded that gas does not invade the cement matrix as long as the cement pore pressure remains above the formation gas pressure.
Two new exploratory gas wells were drilled at Ten Section field in September of 1985. Electric, sonic, and mud logs indicated economic reserves in multiple gas sands in both wells.
Reliable reservoir fluid saturation data are important to the over-all planning for prospective supplemental recovery projects. A trial-and-error graphical procedure, based on the fractional flow equation and using field production data, has been developed to determine these values with reasonable accuracy.
The preliminary analysis of a reservoir to determine the feasibility of supplemental recovery operations requires a reliable estimate of reservoir fluid saturations, and a judgment must be made as to the degree of accuracy desired. An increase in the complexity, data requirements, and sophistication of the various available solution methods does not necessarily imply that the results will be more precise. The decision as to which solution method should be used is sometimes difficult to make. This decision should consider, among other things, engineering manpower requirements for the various alternatives, the quality of existing data, and the sensitivity of the project economics to a reasonable variation in fluid saturation levels. Average oil, water, and gas saturations for a reservoir as a whole are usually determined by a pressureTroducdonhistorymatchusingconventional material-balance methods. More sophisticated numerical simulation techniques are generally used to determine reservoir saturation distributions. Simulation work can be time consuming and expensive when efforts are made to determine accurately the saturation distribution by attempting to match the individual performances of a large number of wells. A trial-error graphical procedure has been developed as an alternative to the more sophisticated methods. Because of its easy use, the procedure may be considered as an efficient and economical application of engineering effort for planning purposes. An application of this technique is illustrated for the Ten Section field, Kern County, Calif.
The Ten Section field, located near Bakersfield, Calif., was discovered in 1936; development progressed continuously until 1942, at which time 126 wells had been completed within the originally productive area of about 2,200 acres (Fig. 1). The Ten Section structure is a gently dipping (3 deg. to 7 deg.) doubly plunging anticline. The producing measures are the upper Miocene Stevens turbidite sands, which have been subclassified as Zones 1, 2, and 3. The Zone 2 reservoir includes the intermediate series of these sands that are bounded above by a thin continuous shale varying in thickness from 5 to 10 ft and are separated from the deeper measures by an extensive thin shale. The sand intervals of the upper Stevens turbidite sequence are composed of individually graded and rythmically bedded deposits. Core observations indicate that the cycles average 2 to 3 ft in thickness and that the sands composing each cycle display the usual turbidite variation in grain size (grading from coarse at the base to fine at the top). Both sands and shales within Zone 2 are discontinuous and few units are correlative across the field. Original oil in place within the Zone 2 volume of 170,000 net acre-ft is estimated to have been 91 million STB. About 35 million STB of oil (38.5 percent) have been produced to date. An active partial water drive is currently maintaining reservoir pressure in most portions of the field and an ultimate primary recovery efficiency of 41.5 percent of the stock tank oil originally in place should be realized. Table I lists the pertinent reservoir properties. About 58,000 acre-ft of the crestal portion of the reservoir are currently productive (Fig. 2). Part of this volume has been swept by natural water influx, as evidenced by the high producing water cuts in many of me wells. Reservoir heterogeneities account for the lack of an easily discernible common water level in Zone 2.
Section I-Paper 36 INVESTIGATIONS INTO DIRECT OIL DETECTION METHODS BY V. A. SOKOLOV," F. A. ALEXEYEV," E. A. BARS," A. A. GEODEKYAN," G. A. MOGILEVSKY," Y. M. YUROVSKY" AND B. P. YASENEV" ABSTRACT. The report gives the results of comprehensive researches carried out during recent years in the U.S.S.R. on the development and application of geochemical, biochemical and radiometric methods of prospecting and exploring oil and gas fields. The direct geochemical indications of oil and gas considered are: natural oil gases, bitumens, bacteria-assimilating migrating hydrocarbons and other indications due to the effect of migrating gases on the surroundings, as well as organic substances of crude oil origin dissolved in underground waters. Extensive research on gaseous, bacterial and other geochemical anomalies under various geological conditions (geosynclinal areas, platforms and transitional zones) revealed the relationships of distri- bution of geochemical anomalies at various stratigraphie levels of sections and their relation to the deep sources of migration. The data on the forms of gaseous and bacterial anomalies and on the conditions of their formation are generalized. Results are given of practical work involving the use of gaseous and microbiological surveying, gas logging, and other methods of exploration. Analysis of the effectiveness of direct oil and gas detecting methods shows that under favourable geological and geochemical Conditions the proportion of correct predictions is as high as 70 per cent. For more extensive practical application of direct methods in oil and gas prospecting it is recommended: 1) to select objects of investigation more carefully; 2) to increase the depth of sampling in platform districts ; 3) to make extensive use of structural exploratory and seismic wells for gasometric surveying, and 4) in new regions to carry out in the reconnoitering stage primariIy regional gas microbiological and other investigations on soils and underground waters of the upper sedimentary layer. Gas logging techniques involving the use of chromatographic analysis are described. Direct methods deserve wider applications in prospecting for oil and gas deposits, especially in new regions; also further research is needed to improve these methods.
. Cette communication présente succinctement les résultats de recherches complexes pour- suivies ces dernières années en U.R.S.S. pour la mise au point et l'emploi de méthodes géochimiques, biochimiques et radiométriques de l'existence de gisements de pétrole et de gaz. Comme indice géochimiques directs de présence de pétrole et de gaz, on examine les gaz naturels de pétrole, les bitumes, les bactéries tests d'hydrocarbures en migration et autres indices conditionnés par l'action de gaz en migration sur le milieu environnant, aussi des matières organiques dissolues dans les eaux souterraines ayant le pétrole pour origine. Sur la base de nombreux tr
ABSTRACT The paper describes the two-phase vertical-lift function, explains the hydraulics of natural flow, outlines two-phase flow through orifices, summarizes methods for estimating individual well capabilities, and includes approximations for solution of natural flow and gas-lift problems for tubing of the 1.66-, 1.90-, 2.375-, 2.875- and 3.50-ln. API sizes, and crude oils in the gravity range from 25 to 40 API INTRODUCTION Advances in knowledge of the different lifting methods do not lend themselves to evaluation quickly or in simple economic terms. In the aggregate, however, they constitute the necessary basis for improved lifting policies and profitabilities, wherever oil is raised. Production by natural flow rightly tops the list of lifting methods, inasmuch as it produces more oil than all other methods combined. It proceeds with minimum cost in relative absence of operating difficulties; and is relinquished finally in an atmosphere charged with regret, and supercharged with expletives intended to fortify the conclusion that the stoppage is an irreversible act of Providence. Nevertheless, production men have been haunted for years by the thought that a more definite knowledge of flowing performance would suggest means of resuming flow after premature stoppages, permit more effective well control, more appropriate How-string selections, and serve in general to Increase the proportion of oil quantities economically recoverable by natural flow. Development of organized information on vertical-flow has been so far a matter of slow growth. A presentation in 1930 of the basic theory by the late Professor Doctor J. Versluys provided an initial impetus for current developments, but has been applied only to a limited extent because of practical difficulties in evaluating factors which appear in the Versluys differential. An Interesting attempt to solve the problem of two-phase vertical lift testing flow through short (67-ft) tubes was reported in 1931 by T.V. Moore and H, 1). Wilde. Failure of this project to provide the desired generalization seems attributable to use of tube lengths so short that representative conditions were not attained. kemler and Poole, in a paper on flowing wells presented before the American Petroleum Institute in 1936, developed a limited correlation between gas-liquid ratio and pressure drop per unit of tubing length, and explained a method of estimating flowing life. The work of C. J. May and A. Laird4" resulted in vertical-lift generalizations well adapted to predict results within a restricted range of conditions. The interesting paper by Poettman and Carpenter appeared subsequent to the time of derivation of the material here presented. "Gas-Lift Principles and Practices" by S. F. Shaw, the pioneer consultant on vertical flow, provides an interesting discussion of gas-lift history and methods with correlations which, though limited in scope, were none the less useful. Shaw's observation, that power functions may be applied in approximating the relationships between minimum gas-lift intake pressures and given liquid production rates, has been used here. The excellent paper by L. C. Babsone added considerably to knowledge of vertical Bow, particularly in the range for gas-liquid ratios greater than 2.0 Mcf per bbl. To a large extent the present paper is a result of reviewing Babson's data and work after adding a considerable fund of depth-pressure
ABSTRACT Considerations given to the selection of light-weight tubes in lieu of heavier drill pipe are discussed. Experiences using tubing as drill pipe are given, as well as detailed analyses of comparable drilling progress and costs. lt is concluded from experience to date that in many instances drilling costs can be reduced by the use of tubing in place of drill pipe. As an integral part of the continuous effort to reduce well costs, the Pacific Coast area staff of Shell Oil Company undertook a study of slim-hole drilling. These studies were conducted to determine optimum hole and drill-pipe sizes and included such factors as circulating rates and pressures, mud flush, rising velocity and availability of suitable sidewall sampling, fishing and testing tools. Because theoretical and practical considerations were strongly in favor of the 64-in. hole using 34-in. drill -tubes, this combination was accepted as a basis for slim-hole operation. Studies of possible drilling units that could be moved legally over California highways led to the conclusion that equipment designed to handle 10,000 ft of 34-in.. drill pipe did not exist; and, furthermore, that it was extremely unlikely such equipment could or would be built for some time. However, it was recognized that existing portable equipment could be used to drill deeper if the drill pipe loads could be reduced. Further studies along this line, which included a review of experience with acme-thread drill casing used for drilling in the Ten Section Field, led to the selection of 9.3-lb 34 1/2-in. J-55 API upset tubing with acme-type threads for the drilling of 6 3/4-in. slim holes . A portable drilling unit powered with a 150-hp diesel engine was available for testing the practicability of using tubing for drilling; and it was reasoned that inasmuch as this unit could successfully handle loads equivalent to 3,500 ft of 4-in. 16.6-lb drill pipe, its depth range could be extended to 6,500 ft through the use of 9.3-lb tubing as drill pipe . The selection of 9.3-lb tubing was based primarily upon availability of an API standard tube, plus the fact that 24-in. tubing had been successfully used in drilling-in operations in the Ten Section Field. Therefore, it was believed this tubing would have the ability to transmit the necessary torque required for rock-bit drilling. Grade J tubing was preferred to grade N because it has more resistance to shock, as indicated by elongation specifications. Acme-type threads were selected because they had been used so successfully in drill-casing operations in the Ten Section Field and also because this type of thread could be obtained without waiting for the manufacture of special joints. Also, it was believed that an inexpensive tool joint such as a tubing collar, if it could be used, would contribute materially to the economic success of slim-hole drilling. As experience with drill casing had definitely proved , the desirability of using power tubing toags to spin up the pipe as it is run in the hole, and , the necessity for using specially built tong jaws which would evenly distribute over a large area the crushing force developed while breaking out the tubing, this equipment was obtained before starting the drilling test.
The Ten Section oil field is located in the San Joaquin Valley in KernCounty, California, about 12 miles southwest of Bakersfield in Township 30South, Ranges 25 and 26 East. The accumulation is in a low relief anticlinaldome and has a productive area of approximately 2,200 acres. Discovered in 1936as a result of seismic work, it was the first field on the floor of the Valleyto obtain production. It had a small primary gas cap, and since its inceptionhas been produced by depletion with controlled withdrawal from the gas cap tominimize blowthrough.
Structure and Stratigraphy
The Ten Section structure is an elongated anticlinal dome with flank dips ofonly about 7 degrees. A map of the field, now fully developed, and a compositelog are shown in Figs. 1 and 2. Contours shown on the map are on the top of thefirst zone, or Marker XA as indicated on the composite log.
As shown, the field has a productive closure of only some 350 feet, and thereapparently is no faulting in the reservoir.
The productive measures in Ten Section are of Upper Miocene age and are knownas the Stevens sand. They contain thin, irregular shale or siltstone streakswhich vary considerably in stratigraphic position and thickness and apparentlyare rather discontinuous. As a result, individual sands and shales cannot becorrelated over any appreciable area, which makes it difficult to subdivide thesand body into separate zones which are distinct throughout the field. However,there are two fairly persistent siltstone bodies that at the time ofdevelopment were considered to divide the productive measures into threegeneral zones.
The first, or uppermost zone is productive over the entire field and has anaverage thickness of 180 feet, of which some 65 per cent is sand. It had aprimary gas cap in the crestal area with an areal extent of 930 acres. Thesecond zone has a productive area somewhat smaller than the first zone, but itdid not have any original gas cap. It has an average thickness of about 360feet, of which 55 per cent is sand. The third zone has a very limited arealextent and a maximum productive thickness of 100 feet, of which 80 per cent issand. Recently, a deeper oil accumulation, termed the "53" sand, wasdiscovered, but it is not discussed in this analysis. In the first and secondzones the water table was at 7,980 feet subsea, while in the third zone it wasat 8,080 feet subsea.
The Ten Section field is approximately 10 miles southwest of Bakersfield,Kern County, Calif. (Fig. 1). There is no surface evidence of the existence ofthe Ten Section structure, which subsurface exploration has shown to be agently folded, anticlinal dome. Regionally, this field occurs as a fold in thedeeper beds of the gently rolling floor of the San Joaquin Valley. It is on theeasterly slope of the valley, its position with relation to the axis of thissyncline not having been determined.
The field was discovered by Shell Oil Co. with the completion of well
Stevens A-I, on June 2, 1936, at a depth of 7888 ft.