Downhole Gas Research Articles

Effect of Gaseous Fluids on Submersible Pump Performance

Summary This paper reports the results of two independent laboratory investigations on the effect of free gas on centrifugal submersible pump performance. One investigation used air and water as the working fluids, with the free gas allowed to escape out an annulus. A separate investigation was conducted using diesel fuel and CO as the working fluids with intake pressures up to 400 psi. The results of the two investigations agreed in general at low pressures, where gas volumes exceeding 10% by total volume began to cause serious reduction in pump performance curves. Better performance at higher pressures with the same gas volumes present was found to occur at higher pump intake pressures. Introduction The presence of free gas has been recognized as having, in general, a detrimental effect on the performance of a submersible centrifugal pump. This paper describes two independent test programs undertaken to define the effect of the gas on the performance of this type pump. The effects of the free gas show up as a deterioration of the head-capacity curve, such as areas of unstable head production, and effects similar to cavitation at higher flow rates. Depending on the amount of free gas through the pump, these effects may vary from slight interference to gas locking. Gas interference is indicated on the surface amp chart by rapid variation of the motor loading. Gas locking occurs when the pump ingests too much gas and actually stops pumping because its head (or pressure) production is drastically decreased. This causes the motor to unload and to shut down because of excessive underload (control protection). When designing an electric submersible pump for a gassy application, it is very desirable to know the amount of free gas the pump can tolerate and to compare this to the downhole gas conditions. Test Facilities and Procedures Test facilities, methods of data collection and reduction, and results are presented for two independent test programs. Tests conducted by Amoco Production Research Co. involved using water and air. A separate program was conducted for Centrilift Hughes Inc. at the R.C. Ingersoll Research Center using diesel fuel and CO. In both programs, the purpose of the tests, was to define the performance of typical submersible centrifugal pump stages when free gas volumes were introduced at the pump suction under various flow and pressure conditions. If this information is available and can be shown to be extended to field use in the petroleum industry, improved pump design or selection of gas separation equipment can be made for the many cases where pumps are needed to handle gassy fluids. The two test facilities and programs are described, and results from each are presented and discussed. Facilities and Procedures for Air/Water Tests The test facility at Amoco was an aboveground installation, in which the flow patterns and distribution of air volumes could be viewed. For simplicity, water and air were chosen as working fluids. A schematic of the test loop is shown in Fig. 1. The pump housing, containing five Centrilift I-42 pump stages, was installed in an 8-in.-OD, 7-in.-ID plexiglass tube. JPT P. 2922^

Initiation of an In-Situ Combustion Project in a Thin Oil Column Underlain by Water

Summary An in-situ combustion project was initiated in the Caddo Pine Island field in a thin oil column underlain by a water zone. An inverted five-spot well pattern was selected for the project, and the formation was ignited in Sept. 1980 to evaluate the potential of enhanced oil recovery by a combustion process. This paper presents engineering and laboratory procedures used in evaluating the reservoir for in-situ combustion. The program used to monitor the project performance, including both surface and subsurface measurements, is discussed. The paper reviews the design and installation procedures for the project wells and surface facilities, and presents project results. Introduction An in-situ combustion project has been initiated in the Nacatoch sand underlying the Harrell Fee lease in the Caddo Pine Island field, approximately 30 miles (48.2 km) northwest of Shreveport, LA (Fig. 1). The Nacatoch formation is an Upper Cretaceous semiconsolidated, friable, fine-grained sandstone reservoir located approximately 1,000 ft (304.8 m) below ground surface [800 ft (243.84 m) subseal. The formation contains a thin [29-ft (8.83-m)] column of high-viscosity, low-API-gravity oil that is underlain by a thick [100-ft (30.48-m)] ‘water zone. Primary recovery from the reservoir was low because of the absence of reservoir energy and because of the unfavorable mobility ratio between the viscous crude and the underlying water. Reservoir fluids and matrix properties are presented in Table 1. A typical well log and a structure map of the Nacatoch sand in the project area are shown in Fig. 2. The inverted five-spot well pattern (Fig. 2) encompasses five acres (20.23×10 m) and is centrally located within the Harrell Fee tract. The project was initiated by injecting air in Well 6, which was ignited on Sept. 17, 1980. Since ignition, daily gas analysis from the four producing wells indicates that an efficient combustion front is in progress within the pattern. A reservoir simulator was utilized in selecting and evaluating the pattern size and configuration for the insitu combustion project. Inverted five-spot, seven-spot and nine-spot well patterns ranging in size from 3 to 10 acres (12.14×10-3 to 40.47×10-3 m2 were considered. A 5-acre (20.23×10-3m2) pattern was chosen to obtain results from the project at an early date. All five wells in the pattern were drilled through the Nacatoch sand, and the casing was cemented by using a special heat-resistant slurry. Conventional and sidewall cores were taken from all wells (1) to aid in reservoir definition, and (2) to provide core material for laboratory tests. Logs from all five wells indicated sand continuity throughout the project area. Well completions were designed to accommodate both dry and wet combustion. Laboratory studies consisted of dry and wet combustion tube runs performed on core material from injection Well 6. The optimal injection water/air ratio (WAR) for the project was determined from the laboratory tests. The production facility is designed to handle normal oilfield problems as well as difficult emulsions and sand production associated with in-situ combustion projects. Air injection is supplied by a compressor rated at MMcf/d (28.32×10(3) M3/d) and a second standby compressor that was used during the ignition phase of the project. Ignition of the reservoir was accomplished by a downhole gas burner in the injection well. Ignition was confirmed by a downhole thermocouple. A program was developed to monitor project performance and combustion zone efficiency. The program includes bottomhole temperature and pressure (BHT and BHP) surveys as well as chromatographic analysis of the produced gas. Generally, the project response has been satisfactory. Process Selection The Nacatoch sand was selected as a candidate for thermal recovery methods. The reservoir contains a thin column of high-viscosity oil underlain by water. JPT P. 2233^

Fluoroelastomer Polymers—Compounding and Testing for Downhole Environments

Abstract A laboratory screening test simulating sour gas downhole conditions has been developed that provides directional information on the factors that control elastomer seal performance in this harsh environment. The results of this test have been correlated to environmental testing of O-rings in simulated downhole conditions using sour crude oil at 203°C and evaluating the pressure failure over the range of 69 MPa to 138 MPa. The results of this testing program have demonstrated the factors that affect overall seal performance for commercially available fluoroelastomer raw gums in downhole environments in the following order of importance: 1. a vulcanized compound modulus at 50% elongation of greater than 6.9 MPa, 2. cure type order of preference of peroxide > bisphenol > diamine, 3. increases in fluorine level from 65 to 69 weight percent have little effect on seal performance in conditions evaluated, and 4. the compound hardness is not as important a factor in predicting compound failure or success as is molecular weight selected that results in elongation of 70–100% at high filler loadings to achieve high modulus. The laboratory screening/environmental testing sequence reported here has proven successful in predicting fluoroelastomer properties necessary to manufacture seals for actual downhole service.

Some Recent Developments in Drill-Stem Test Interpretation Useful to Explorationists in Tight Gas Sand Plays and in Identifying Reservoirs with Linear Geometry: ABSTRACT

Two major areas of recent development in drill-stem testing are of particular interest to geologists. The first is the use of closed chamber DST's to evaluate the very tight gas sands currently under intense exploration in areas such as Alberta's Deep Basin and various intermontane basins in the United States Rocky Mountain province. Conventional DST's of such zones frequently provide little usable data, especially in very deep wells where the time for gas to fill the drill string, reach surface, and thereby be detected, commonly exceeds allocated flow time. This problem of definitive identification of gas presence and verification of rate is overcome where closed chamber tests are utilized, since downhole gas influx is determined from instantaneous surface pressure chang . Interpretation processes are explained which have enabled initial detection of gas and rate verification, and have sometimes allowed differentiation between truly impermeable and badly damaged zones. Field examples from the Deep Basin of Alberta are shown together with results after completion. Other applications are shown. The second development is the use of DST data to identify reservoirs with linear flow geometry. Geologic situations where flow into the well bore during a test can be considered linear rather than truly radial include long narrow reservoirs with parallel boundaries such as channel sands, zones bounded by parallel sealing-fault boundaries, or naturally fractured reservoirs where an open fracture intersects the well bore. Many such situations may be identified utilizing simple graphic techniques involving plots of the pressure buildup during shut-in periods versus the square root of various time functions. These plots allow extrapolation to correct reservoir pressure (not possible with conventional Horner plots which assume radial flow, and which sometimes result in false interpretation of depletion). End_of_Article - Last_Page 977------------

High-Temperature Thermal Techniques for Stimulating Oil Recovery

Abstract Artificial ignition methods that were developed primarilyto ignite in-situ combustion projects are now used to initiatehigh-temperature thermal stimulation treatments onproduction and injection wells. Where well productivity islimited due to the viscous nature of the crude oil at reservoirconditions, the application of high-temperature treatmentsusually increases oil production rates. A secondarybut often highly beneficial effects is attributed to the removalof certain immobile hydrocarbon materials thatsometimes plug the wellbore, greatly restricting the oilproduction rate. Consolidated formations are oftenshattered by the high-temperature process, or else theirpermanent increase in oil production rates. Similarly, water-injection rates can be increased substantially and thehigh-temperature process is particularly applicable wherelow-permeability formations are to be water flooded. Electricalheaters or down-hole gas burners are used to elevatewellbore temperatures. The equipment and procedures forinitiating the high-temperature thermal treatments are discussed. Introduction The use of thermal energy to correct or improve wellperformance is becoming more important as wider usageof thermal processes results in the discovery of newapplications to related problems. The first widespread use ofthermal methods was in low-temperature production wellstimulations using bottom-hole heaters. While economicallysuccessful where properly applied, this technique waslimited, in that there was no appreciable temperature effecton the reservoir or its fluids at a distance greater thanabout 1 ft from the wellbore. Field application of the in situ combustion processresulted in the development of high-temperature ignitionequipment and techniques. Most ignition methods usegas-fired or electrical down-hole heaters to ignite the oilformation. With these new high-temperature ignition toolsavailable, it soon became evident that many beneficialresults could be obtained by treating a wellbore withtemperatures in the 900 to 1,200F range. Data obtained fromigniting a producing well and moving the burning front ashort distance into the formation indicated oil productionstimulations in excess of that which could be predictedfrom viscosity reduction alone. Investigation led to theconclusion that the high-temperature treatment resulted inphysical changes in the mineral matrix that increased thepermeability or flow capacity of the reservoir rock. Fieldexperimentation to evaluate this phenomenon with injectionwells in waterflood operations furnished proof of thischange in rock properties. This also led to the conclusionthat waterflood recoveries could be accelerated andpossibly improved by proper application of this process towaterflood injection wells. Mechanism of Thermal Stimulation The mechanism of in situ combustion has beendiscussed in detail in the literature. The temperaturedistribution associated with the in situ combustion process, however, is important in thermal stimulation work, andmodifications of the temperature distribution in the vicinity ofthe wellbore are discussed below. JPT P. 1007ˆ

Laboratory and Field Tests on Titanium for Oil Field Pump and Valve Parts

Abstract Laboratory and field tests are reported for titanium parts for gas lift valves and down-hole oil well pumps. While titanium performed well in the laboratory tests using aerated fluids, and did well in field tests of gas lift wells, similar trials in wells pumping sour crude oil well showed titanium to be inferior to normally used materials. Authors conclude titanium is suitable for use in gas lift valves and could be competitive to presently used materials at a lower price. They conclude titanium is not suitable for use in oil well pumps, but might perform better if hardened. It also is at a competitive disadvantage to commonly used materials costwise. While titanium is cathodic to materials commonly used in oil wells, no marked corrosion was attributed to this property after exposure of coupon sets in a producing well. Titanium was found resistant to abrasion by sand-laden aerated oil well fluids in laboratory tests. 6.3.15, 8.4.3