High Gas-oil Ratio Research Articles

A Simple Low Cost Method for Determining the P.I. of High Gas-Oil Ratio Pumping Wells

Abstract Determining productivity index (PI) is a problem that confronts operators in many areas problem that confronts operators in many areas where beam units are used. With sucker rod pumping, it is not uncommon for equipment to pumping, it is not uncommon for equipment to be over or under designed because of a lack of productivity information. This paper describes a simple, low-cost technique for determining the PI of a pumping well which will be referred to as the "shut-in annulus" test. The method is especially useful in areas where gas and foam limit the use of conventional fluid level techniques. A two-pen recorder is used to measure tubing and casing pressure, permitting an accurate estimate of working pressure at pump depth. Using this information along with data on static pressure, producing rate, and gas-oil ratio, the PI can be calculated. A comparison of calculations by this method to measurements with bottom-hole pressure gauges was made, and the results pressure gauges was made, and the results showed that the "shut-in annulus" test gives a reliable estimate of PI. A group of deep, gaseous pumping wells was then tested using this technique. No productivity information was available at the time of testing, but all of the wells were suspected of having additional producing capacity. PI's were calculated and changes in production equipment were made to satisfy the requirements of individual wells. Based on the results of testing, it is concluded that the method gives a reliable estimate of PI, and it has consistently proven to be a good "yard-stick" for production purposes. Introduction Accurate productivity index (PI) information is needed to design artificial lift equipment and its importance is increased where there are no allowable restrictions. Many methods with varying accuracy are used to find the PI of beam pumped wells. A common method is to fix the working fluid level using a well sounder and calculate flowing bottom-hole pressure with an estimated gradient; however, gas, foam or paraffin frequently cause erroneous results. Another method is to run a gauge below the pump to record pressure while the well is produced. This procedure is not widely used because of time and expense. This paper describes a simple, low-cost technique (called the "Shut-In Annulus Test") for determining the PI of a pumping well.

Evaluation of Surface Back - Pressure for Continuous - And Intermittent - Flow Gas Lift

Abstract To study continuous- and intermittent-flow gas-lift wells, it is necessary to evaluate the facilities that the well fluids must pass through to reach the storage point. This paper deals with surface back-pressure and its effect on continuous-and intermittent-flow gas lift. Particular emphasis is placed on inadequate-sized flowlines for continuous flow and intermittent slugs produced against surface chokes.Numerous field tests on continuous-flow gas-lift wells show the resulting increase in production due to reducing surface wellhead pressure. A method is presented to predict and apply surface back-pressure.Controlled experimental tests show the results of producing intermittent slugs against varying surface choke sizes. A means of calculating the weighted average bottom-hole pressure is given for an intermittent cycle. This average pressure increases considerably as the surface choke size is decreased. These calculations show when a chamber installation should be considered for intermittent lift. Introduction One of the reasons gas-lift studies are made difficult is that the system concerned starts at the sand face at the bottom of the well and does not end until the storage facilities are reached. The whole system must be considered in the study because any alteration in the system, from one end to the other, will affect the drawdown at the sand face and the corresponding fluid production rate of the well. This paper deals particularly with surface back-pressure and its effect on production rates.Serious loss of production occurs when gas-lift wells are produced against excessive back-pressures at the surface. Surface back-pressure is considered to be that pressure found inside the christmas tree, just upstream from the flow-wing. This excessive back-pressure is generally caused by:high separator pressure;choke in the christmas tree or flowline;long flowline;inadequate-sized flowline;restrictions in flowline such as paraffin, scale deposits, crimped flow line, etc; anda nonstreamlined christmas tree incorporating a large number of sharp bends. Numerous field and experimental tests were conducted in actual gas-lift wells for both continuous and intermittent flow to show the effect of these restrictions. It has long been known that the production of fluids from a gas-lift well may be materially reduced by producing this fluid against a surface restriction or against high surface back-pressure. It has also been a matter of education in some instances to show why this additional back-pressure reduces the total output of produced fluids (oil, gas and water).Admittedly, there are some instances wherein a well must be treated very carefully and, in turn, excessive pressure drawdown must be avoided. This is particularly true for wells that are known to produce sand and for wells that are producing with high solution gas-oil ratios. In some wells excessive drawdown has created a gas phase around the wellbore, which in turn increases the permeability to gas and, hence, reduces the oil production.It is not the purpose of this discussion to deal with those wells in these two categories; rather, it is assumed we are dealing with wells of the type where a maximum drawdown is necessary to obtain maximum fluid production. In turn, it is desired to produce these fluids with a minimum amount of injection gas. Continuous-Flow Gas Lift Introduction It is common practice throughout the oil field to increase the fluid production rates from continuous-flow gas-lift wells by streamlining wellheads, enlarging, shortening and streamlining flowlines, and reducing separator pressures.In turn, this reduces the surface back-pressure on the well. Although this is common practice, it is known that a large percentage of continuous-flow gas-lift wells are still being excessively choked to as much as one-half of their efficient production capabilities by excessive back-pressures. JPT P. 243^

Effect of Gas-Oil Ratio on the Behavior of Fractured Limestone Reservoirs

Abstract The porosities of fractured limestone reservoirs can be divided into two broad types in accordance with their effects on fluid distribution and fluid flow. In the coarse porosity, gravity segregation takes place freely and the resistance to fluid flow is very small. In the fine porosity there is no segregation and a high resistance to flow, and it has relative permeability characteristics similar to tight sandstones. By analyzing the affect of the two porosities it is concluded that in some cases to recover the maximum amount of oil it is necessary to remove large quantities of gas from the reservoir by producing at high gas-oil ratios. In this manner the fine porosity is drained of its oil and the gas-oil contact drops slowly permitting higher production rates from the oil leg. Since this conclusion is contrary to widely accepted principles of conservation, a mathematical model (Fig. 1) was constructed to duplicate the conditions desired. The behavior of the model indicates that under certain conditions it is possible to recover more oil by producing at high gas-oil ratios than by production at low gas-oil ratios, and that the rate of production is affected more by gas shut-offs than by the decrease in pressure (Figs. 2, 3, 4 and 5). Introduction It has been noted that certain limestone reservoirs behave in such a way as to indicate that there are two distinct types of porous spaces available for fluid storage and fluid flow. Regardless of the nature of these porous spaces the distinguishing characteristic is that in one type of porous space there is definite gravity segregation between the oil and the gas; while in the other, the gas evolved tends to remain distributed equally throughout the reservoir. For the sake of simplicity the porosity in which gravity segregation takes place at a fast enough rate to affect the behavior will be called "coarse porosity", while that in which this is not so will be termed "fine porosity".

Pressure Maintenance by Inert Gas Injection in the High Relief Elk Basin Field

Published in Petroleum Transactions, AIME, Volume 204, 1955, pages 49–57. Abstract Pressure has been maintained in the Elk Basin Tensleep reservoir since the initiation of inert gas injection in Sept., 1949. Oil is being produced under conditions favorable for gravity drainage, including high angle of dip, appreciable structural closure, and fairly good permeability. Results being obtained are high per cent recovery of oil-in-place, sustained field productivity, reduced operating problems, and recovery of plant products. The high recovery has been calculated by application of the gravity drainage theory described in an earlier AIME paper. It is also confirmed from field performance by comparing oil recovery to date with gas cap space voided. General Information The Elk Basin field lies in Park County, Wyo., and Carbon County, Mont., approximately 50 miles east of Yellowstone Park. Located at the northern end of the Big Horn Basin, the field is situated on an elongated asymmetrical anticline (Fig. 1). The pressure maintenance project covered by this paper involves the Embar-Tensleep reservoir in this multi-pay field. Discovered in Nov., 1942, it has a proved productive area of over 6,300 acres. It consists of the 210-ft thick Tensleep sandstone of Pennsylvanian Age overlain by 40 ft of Embar dolomite of Permian Age. The two formations apparently are in communication with each other and are produced as a common source of supply. As 98 per cent of the reserves are contained in the Tensleep sandstone, in this paper the Embar-Tensleep reservoir will be called simply the Tensleep. The reservoir is found at an average depth of 4,900 ft, is approximately 7 miles long and 2 miles wide, and has a maximum oil productive closure of 2,330 ft. The strata dip an average of 21° on the west flank and 45° on the east. There are presently 132 Tensleep wells in the field drilled on 40-acre spacing; of these, 17 are shut in because of high gas-oil ratio (GOR) and eight are gas injection wells.

Relationship between Specific Gravity of Gas and Gas Oil Ratio

Measurement of specific gravity of gas of a well which is producing under high gas oil ratio is used for assuming the amount of channelled gas in gas injection method.

Mile Six Pool - An Evaluation of Recovery Efficiency

Abstract The Mile Six pool is located on the La Brea-Parinas Concession ofInternational Petroleum Co., Ltd., in northwestern Peru on the west coast ofSouth America. The reservoir pressure in this pool has been maintained within200 psi of its initial value throughout its history, and gravity drainage hasplayed an important role in the production behavior. It has now produced 95 percent of its estimated ultimate recovery. It is estimated that this interesting oil pool will ultimately produce 67per cent of the initial oil in place and that the resulting residual oilsaturation may be as low as 19 per cent of the pore volume (29 per cent of thehydrocarbon pore volume). An evaluation of reservoir rock and fluidcharacteristics and ultimate oil recovery is presented. Introduction This study of Mile Six pool was made to evaluate its performance accordingto latest available information. The production performance of this pool hasbeen discussed in various articles in the past, and the reported behavior hasbeen used as an example for application of computation procedures for gravitydrainage depletion and as an illustration of field behavior under gravitydrainage or expanding gas cap drive. There have been wide variations inreported values of initial oil in place, reservoir oil volume factor, connate-water saturation, volume of effective sand, and ultimate recoverybecause of the paucity of reliable basic data. These various factors have beendetermined as accurately as practicable with the latest available information, and this evaluation is presented herein. The production history of Mile Six isan excellent example of gravity drainage depletion with effective pressuremaintenance by gas injection. General Mile Six pool was discovered by cable-tool drilling in November, 1927, whenwell 1996 was completed in the Parinas sand. After slow development with cabletools and sporadic production, the pool was opened to continuous production inNovember, 1933, and development was completed with rotary rigs. Pressuremaintenance was started in December, 1933, by returning gas to up structurewells. Most of the development was completed by 1937, but some additional wellswere drilled in the period 1939–1947, and several old wells were deepened. Atotal of 46 oil and gas wells and 4 dry holes were drilled on approximately7-acre spacing. Of the producers, 21 are now flowing, 2 are pumping, 4 are gasinput wells, 3 are abandoned, 1 is a gas well shut in, and 15 are shut inbecause of non-commercial production or high gas-oil ratio. The locations ofall wells are shown on the map of Fig. 1. T.P. 3695

The Novinger Pool: ABSTRACT

The discovery well of the Novinger pool was drilled in the latter part of November, 1950, on the T. B. Novinger lease, Sec. 26, T. 33 S., R. 30 W., Meade County, Kansas. At the present time 32 wells have been drilled, of which 27 produce from the Marmaton, 3 from the Morrow, 1 from the Chester, and 1 gas well from the Atoka. Initial potentials on the wells range from 2,204 to 49 barrels of oil per day. The average monthly production of the field is 42,000 barrels of oil. Total accumulative production to the first of August, 1953, is approximately 475,000 barrels of oil. Most of the oil produced is from a porous limestone of Marmaton age. This reservoir is an elongate reef-like body with a north-south trend. Lithologically, it is a relatively coarse textured oolitic limest ne with a large percentage of organic debris. The northern limits of the field have been delimited by three wells that cored dense shaly limestone in the stratigraphic interval represented by the Novinger pay on the south. The southern limits of the field are not known. Pay from the Atoka is from a relatively tight shaly sandstone of erratic distribution that apparently marks the Morrow-Atoka unconformity. A small amount of gas has been found in the Atoka. Morrow production is from lenticular sands that occur at various levels throughout the Morrow interval. Although 12 wells have been drilled through the Morrow, only 3 in the north end of the pool have had sufficiently well developed sands to be commercial. These 3 are all oil productive with fairly high gas-oil ratios. Chester producti n is from porosity developed in coarsely-crystalline crinoidal limestone at or near the Pennsylvanian-Mississippian boundary. Porosity appears to be secondary and was probably developed by weathering of the Chester limestone during the post-Mississippian-pre-Pennsylvanian erosional interval. Only one well is now producing from the Chester, but another was gauged at 14,000,000 cubic feet of gas per day with a spray of oil before it was completed higher in the hole as a Marmaton producer. No wells have been drilled through the Mississippian. End_of_Article - Last_Page 2608------------

Geology and Development of Poza Rica Field, State of Vera Cruz, Mexico: ABSTRACT

The Poza Rica field is the most important and largest producing field in Mexico. It lies on the Gulf Coastal Plain approximately at 160 kms. south-southwest of Tampico and at 175 kms. northeast of Mexico City. The structure was found originally by geophysics through an almost simultaneous torsion balance and refraction shooting survey. Poza Rica No. 2 well, completed on May 2, 1930, as a gas producer, discovered a subsurface trap drilling in the gas cap in a porous Tamaba limestone at -2,047.3 meters (-6,715 feet). Further deepening of the well brought it in as an oil producer. It was later shut in, because of high gas-oil ratio, in 1933. Later reflection shooting revealed possible extensions and permitted development program. First exploration wells were located at distances between 600 and 1,000 meters (1,968 and 3,028 feet). Completion of wells was first accomplished through 4 3/4-inch liner. Later wells produced through 2½-inch tubing. There are at present 93 wells of which only 4 were dry through lack of porosity in the limestone. Seventy-eight are producing at present. The structure at Poza Rica, as revealed from both seismos and subsurface geology, is a broad anticline in a Tamabra limestone which is open, as yet, toward the west northwest. The highest well, Poza Rica No. 65, found the limestone at -1,947 meters (6,386 feet). The lowest producing well, Escolin No. 2, found the limestone still porous at -2,178 meters (-7,144 feet). Apparently the porous producing zone is due to a reef facies deposited on the highest part of a Cretaceous limestone anticline. Later regional tilting, and subsequent folding apparently displaced the porous zone toward the northeast flank, so that at present no porosity has been found o the south flank. Poza Rica No. 8 and No. 46 are the southernmost wells drilled to the limestone without finding it porous. This field has produced 50,380,902 M3 (316,895,800 barrels) since 1930, and is considered to have a potential reserve of 143,169,000 M3 (900,533,000 barrels). End_of_Article - Last_Page 2314------------

Behavior of Fluids in Oil Reservoirs

It is suggested that greater recovery of oil will be obtained: (1) by maintaining the pressure of the reservoir at high values, (2) by keeping gas, oil, and water segregated in their natural relation as far as possible. To bring about these conditions, low rates of flow are essential, especially in water-drive fields. Likewise, free gas and water should not be produced. The mechanism by which gas and water enter wells may be either one of movement in mass through parts of the sand containing little or no oil, or one of movement with the oil through sands containing oil with water or free gas. Production of gas or water by the first method can often be prevented by repair of the well, whereas little can be done to control these fluids if the second mechanism is responsible for their production. As high rates of flow tend to bring about commingling of free gas and water with the oil, they may cause a premature development of high gas-oil or water-oil ratios. Completion of wells should be given careful attention, and completion and repair operations should be governed by the structure of the reservoir and the condition and nature of the fluids therein. Proper consideration of these factors will result in more successful operations and in greater oil recovery from a field.

The Killing and Well History of Milham Elliott No. 1 and Continental Elliott 12-8 Wells on the North Dome of Kettleman Hills, California

The first producing wells completed in the Kettleman Hills area werenoteworthy for their high gas-oil ratios. As a result they became the object ofcriticism, and controversies arose based on their alleged lack of gasconservation. Ultimately protracted hearings ensued in the District Court ofthe area, and diverse rulings and subsequent modifications have been handeddown affecting the permissible gas-oil ratios. When the Kettleman North DomeAssociation was formed in April, 1931, and the control of the major portion of the North Dome area vested therein, it was decided to produce only those wellswhich had a relatively low gas-oil ratio. Among the wells having the highest gas-oil ratio were the Milham Elliott No. 1(the discovery well) and the Continental Elliott 12–8, drilled as an offset toit. Under the numbering system adopted by the Kettleman North Dome Association, these wells are now known as 88–2P and 1–12P, respectively. Milham Elliott No.1 was originally drilled to 7236 ft., then redrilled to 7108ft. The upper portion of the Temblor Horizon produces with a very large gas-oilratio; production which actually consists of light crude oil with an'accompanying large volume of gas. Little was known as to the location of theTemblor formation at that time but it is now generally accepted that its topwas encountered at 6180 ft., giving 928 ft. of penetration. Initial productionwas estimated at 4000 bbl. of oil and 80 to 90 million cubic feet of gas perday, giving a gas-oil ratio in excess of 20,000 cu. ft. of gas per bbl. of oil.This ultimately increased to a ratio of about 48,000 at the time the well waskilled when it was producing about 1100 bbl. of oil and 52 million cubic feetof gas, with a flow pressure of 1200 pounds. The Continental Elliott 12–8 was drilled to a depth of 6876 ft. with the top ofthe Temblor at 6100, giving a penetration of 776 ft.

Proration of an Oil Field Based on Uniform Allowable Gas Production

The ideas set forth in this paper are proposed for consideration anddiscussion as the result of recent study of various plans for control andproration of gas and oil production from Kettleman North Dome oil field. Theywould be applicable to any oil field during its flush production stage. Theproblems of development and proration are so intimately connected in Kettlemanhills and in many other flush fields that they have both been covered in thispaper. Many are of the opinion that Kettleman North Dome oil field should beconsidered as containing only one zone to its present total penetratedthickness of nearly 1500 ft., and that the hydrocarbon content of this zonegradually changes from dark and relatively low-gravity oil with relatively lowgas-oil ratios on the flanks and plunges to mostly light-colored andhigh-gravity oil with high gas-oil ratios in the higher structural positions, somewhat according to the idealized section shown in Fig. 1. At least the lower400 ft. contains dark oil in the higher structural positions.