Average Oil Production Rate Research Articles

FIELD TEST OF THE INDIGENOUS MICROBES FOR OIL RECOVERY, LEDOK FIELD, CENTRAL JAVA

After selecting several old wells in Cepu, then well LDK-132 was chosen for implementing MEOR technology using "huff and puff" method. For this purpose, fluids samples (water and oil) from Ledok Formation were taken at the wellhead. No core of LDK-132 was available, only cores from LDK-209 and LDK-P1 were found. Core plugs could not be made from the former due to compacted and tightly conditions with a very low permeability of only 0.458 md. The latter with the permeability of 140 md met the requirements of microbial core flooding (MCF) tests, A standard quartz dominated core from Clashach Scotland with permeability almost 800 md was also used to compare with the native core's results. The MCF tests were conducted at the reservoir conditions for both types of core. The native core gave a recovery factor of oil production of 12.58%, while the standard core yielded a higher recovery fac- tor of 21.22% of Sor. Based on these results, the MEOR implementation was conducted on July 8, 1999 by injecting 135 barrels of mixtures consist- ing of formation water, microbes enriched with KKL-11 (Koleksi Kultur Lemigas or Lemigas Cultures Collection) and M4 medium through the annulus of LDK-132. The result showed an increase of average oil production rate, from 3.46 bopd, 6 days before the injection, to 24.85 bopd, 6 days after the injection.

Research on the Enhanced Oil Recovery Technique of Horizontal Well Volume Fracturing and CO2 Huff-n-Puff in Tight Oil Reservoirs.

The low oil productivity of tight oil reservoirs is mainly caused by poor reservoir physical properties such as low porosity and permeability, a small pore and throat ratio, and bad well connectivity, which lead to bad water injection capability and rapid pressure decline for the reservoir. In this paper, an enhanced oil recovery technique for tight oil reservoirs is proposed by combination of horizontal well volume fracturing and CO2 huff-n-puff to improve the reservoir physical properties and increase the flow capability of crude oil. In the initial reservoir development stage, the precise horizontal well trajectory and reservoir volume fracturing scale are designed by analyzing the distribution of sand body thickness and the oily sedimentary facies. The micro-seismic tracking technique is also used to monitor the fracture elongation. When the reservoir energy cannot satisfy the economic limit of oil productivity, the CO2 huff-n-puff technique is applied to increase the reservoir energy quickly. After the precise fracturing technique is used in tight oil Block X, the average oil production rate of six fractured horizontal wells increases by 5 ton (1 ton = 7.33 bbl) at the initial production stage, and the effective oil production increase life lasts for 32 months. When the reservoir energy is supplemented using the CO2 huff-n-puff technique, the oil production rate of pilot experiment well SP-1 increases from 1.9 to 12.8 ton with a cumulative oil increase of 1333.8 ton.

Efficiency Analysis of the Geological-Technical Activities in Severo-Ostrovnoe Field

The work is devoted to identifying the most relevant geological and technical measures carried out in Severo-Ostrovnoe field from the period of its development to the present. Every year dozens of geotechnical jobs (GJ) are carried out at each oil field-works carried out at wells to regulate the development of fields and maintain target levels of oil production. Today, there are two production facilities in the development of the Severo-Ostrovnoe field: UV1a1 and BV5. With the help of geotechnical jobs, oil-producing enterprises ensure the fulfillment of project indicators of field development (Mikhailov, N.N., 1992. Residual Oil Saturation of Reservoirs Under Development. Moscow, Nedra. p.270; Good, N.S., 1970. Study of the Physical Properties of Porous Media. Moscow, Nedra. p.208). In total, during the development of the Severo-Ostrovnoe field, 76 measures were taken to intensify oil production and enhance oil recovery. 12 horizontal wells were drilled (HW with multistage fracking (MSF)), 46 hydraulic fracturing operations were performed, 12 hydraulic fracturing operations were performed at the time of withdrawal from drilling (HW with MSF), five sidetracks were cut; eight physic-chemical BHT at production wells; five optimization of well operation modes. The paper analyzes the performed geological and technical measures at the facilities: UV1a1∦BV5 of the Severo-Ostrovnoe field. Four types of geological and technical measures were investigated: hydraulic fracturing, drilling of sidetracks with hydraulic fracturing, drilling of horizontal wells with multi-stage hydraulic fracturing, and physic-chemical optimization of the bottom-hole formation zone. It was revealed that two geotechnical jobs, namely, formation hydraulic fracturing (FHF) and drilling of lateral shafts in the Severo-Ostrovnoe field are the most highly effective methods for intensifying reservoir development and increasing oil recovery. SXL was conducted at 5 wells. The average oil production rate is 26.6 tons per day, which is the best indicator. Before this event, the production rate of the well was 2.1 tons per day. Currently, the effect of ongoing activities continues.

Pilot Scale CO2 EOR in Mississippian Carbonate Reservoir at Wellington Field in South-central Kansas

CO2 EOR effectiveness and CO2 retention and storage efficiencies in application to Mississippian carbonate reservoirs in Kansas were successfully tested with this small scale field project. Total of 1,101 truckloads, 19,803 metric tons, average of 120 tonnes per day were delivered over the course of injection that lasted from January 9 to June 21, 2016. Current incremental average oil production rate is 34 bbls/day and a total of incremental 6,300 bbls of oil were produced as a result of CO2 injection. Only 12% of injected CO2 was produced back currently (3 months since injection stopped CO2).

Study of cyclic CO2 injection for low-pressure light oil recovery under reservoir conditions

In this paper, the viability of the CO2 huff ‘n’ huff process as a primary means to enhance low-pressure light oil recovery under real reservoir conditions is investigated experimentally. Eight series of corefloods, a total of 35 runs of gas injection, were conducted in a composite core to evaluate the effect of major factors on the performance of the CO2 huff ‘n’ huff process. The factors evaluated included the gas injection rate, pressure depletion rate, maximum injection pressure and chasing gas (N2), minimum termination pressure, and soaking time, etc. The experimental results showed that the first three cycles of a four- or five-cycle operation were the dominant contributors to the total oil production, resulting in a recovery factor of as high as 28.75% OOIP. Furthermore, two parameters used in this work to evaluate the process response, the recovery factor and the average oil production rate, demonstrated sensitivity to different operating parameters. In addition, the oil production of each cycle was observed to be mainly produced by the early production stage, during which the pressure was depleted from the highest level to a certain low level (e.g., 3MPa in this study). Moreover, using N2 as the chasing gas was found to have great potential regarding improving the CO2 efficiency while maintaining the performance of operations at a favorable level. This improvement was more significant in the second and third cycles than in the first cycle of operations. Besides, it was found that, for the first cycle of operations, an intermediate soaking time (e.g., 3h) has a significant advantage over a short soaking time (1h) or a long soaking time (10h) in terms of average cycle oil production rate. However, for the second- and third-cycle injections, 1h vs. 3h of shut-in was considerably more beneficial.

Cyclic Steam Stimulation Effect on Skin Factor Reviewed Case Study

High oil viscosity is a major concern for recovery from heavy oil reservoir. Introducing heat to the formation has proven to be an effective way to improve mobility. The Heat transfer to the oil and reservoir rock is good for thermal recovery. The thermal recovery involves a well-known technique of cyclic steam stimulation which actually effect the nearby well area. Heavy oil reservoir which uses the thermal technique will experience the change of property. Fula North East (FNE) Sudanese field is located in the north-eastern part of Fula sub-basin. According to the development program of FNE, Bentiu layer (of Bentiu group) is the targeted reservoir where the pressure gradient is 285.65 psi/100m, perforation intervals is 540-533 m, and the average oil production rate of single well by applying the cyclic steam stimulation (CSS) is 236 bbl/d. For well- Q, (one of the hot wells) to void the bottom water the average production rate is 191 bbl/d. A minor change is observed in the key properties of the well when the skin affect is varied.

Dynamic solvent process (DSP) for enhancing heavy oil recovery

Solvent‐based heavy oil recovery techniques, such as vapour extraction (VAPEX) and cyclic solvent injection (CSI), have been attracting increasing attention in the past two decades. VAPEX suffers from slow mass transfer and inefficient gravity drainage. CSI is a solvent huff‐and‐puff process and its production period is usually much shorter in comparison with the solvent injection and soaking periods, limiting the average oil production rate over the entire process. This paper proposes a new process, dynamic solvent process (DSP), to exploit the merits of VAPEX (continuous production) and CSI (stronger driving force) and reduce their respective limitations (inefficient gravity drainage and periodic production). DSP is a cyclic process and each cycle consists of two periods: a stable pressure period and a pressure reduction period, through which solvent is cyclically injected and oil is continuously produced. A set of laboratory experiments were performed to validate and analyze the DSP process. During the pressure reduction period of DSP, a foamy oil flow phenomenon was observed when the pressure reached the so‐called pseudo‐bubble point. The foamy oil flow not only enhanced the oil production but also improved mass transfer due to the enlarged oil–solvent contact area. Experimental results showed that the oil production rates of VAPEX and CSI were respectively enhanced by 57–123 % and 17–99 % by DSP with different well configurations.

SAGD Operations in the Presence of Overlying Gas Cap and Water Layer-Effect of Shale Layers

Abstract The technical and commercial success of SAGD projects over the past decade has opened the door to the development of a large number of bitumen reservoirs in Canada, previously thought uneconomical to produce. Some of these reservoirs have overlying gas caps and/or water zones. Some studies have suggested that gas-cap production might "sterilize" the underlying bitumen. Many such studies however, assumed rather thick continuous pays with high permeability, and considered an infinite gas-cap. In this work, a simulation study was conducted to examine the feasibility of bitumen production from a certain project area in Alberta, using the SAGD process, and to study the effect of production from the gas cap. A decision needed to be made as to whether gas production should be delayed until after bitumen production. The large well spacing did not allow a detailed description of the connectivity of the shale layers. The uncertainty was compounded by the geological setting of the study area, a system of channel sands cut through the original marine sand and shale deposits. Since the actual shale connectivity and thickness was unknown, a methodology was developed to incorporate different geological descriptions using the available core and log data. Five reservoir models were developed. Bitumen recovery, average oil production rate, and cumulative steam-oil ratio (SOR) obtained from thermal simulation were the three main parameters used for evaluation of the attractiveness of bitumen recovery operations. These numbers were compared with some of the corresponding values reported and/or forecast for economically feasible operations such as the UTF and Christina Lake projects. The effect of pressure reduction (caused by gas-cap production) on production rate and SOR was also investigated. The results indicated that for conditions considered in this study the effect of gas production on bitumen recovery was minor, and appeared as a small deceleration of the recovery and a small increase in SOR. Introduction Many bituminous reservoirs in Alberta contain overlying gas. The gas owners would like to produce the gas. However, there is concern as to whether or not gas production might adversely affect any possible bitumen recovery process in the future. The primary candidate recovery method for such bitumen formations is the Steam-Assisted Gravity Drainage (SAGD)(1) process. The objective of this study is to examine the feasibility of bitumen recovery from the underlying sands, and to determine the effect of "prior" gas production on the process. The effects of overlying gas and/or water sands on the SAGD process are presented first. This is followed by a discussion of the effect of continuous and discontinuous shale layers, and their incorporation in the numerical model, along with the determination of rock properties. Thermal simulation results and conclusions follow. Background The UTF project demonstrated the viability of the SAGD process for production of some of the bituminous reservoirs of Alberta(2, 3), where more conventional thermal processes are less successful due to immobility of the bitumen at reservoir conditions.

Improved Recovery of Heavy Oil by Vapex with Widely Spaced Horizontal Injectors and Producers

Abstract The Steam-Assisted Gravity Drainage (SAGD) process, which usually employs horizontal injection and production wells, has been applied successfully in producing heavy oil reservoirs. It allows high recoveries to be obtained, at high rates without significant bypass of steam. However, SAGD process, due to the heat loss to the overburden and adjacent formations, can only be used for thick reservoirs with relatively high porosities and oil saturations if there is to be an economic oil/steam ratio. The Vapex process, which uses light hydrocarbon vapors to extract heavy oil from the reservoir, is studied experimentally in the work described in this paper using a new, longer, scaled, packed model. In the process that evolved from the work, liquid solvent (propane, butane, or mixtures) is injected with a small amount of non-condensible gas through a horizontal well at the top of the reservoir to contact and mobilize oil by dilution. The diluted oil is produced by a horizontal well, laterally separated from the injector, and located at the bottom of the reservoir. With this configuration, practical production rates can be achieved without appreciable gas bypass. Solvent is separated easily from the produced liquid by distillation and recycled and this results in relatively low net solvent requirements. Gas fills the vacated pores. The objective of the experiments was to develop process conditions to give high oil production rates with economic solvent requirements. To achieve this, major parameters affecting the Vapex performance were investigated: temperature, pressure, solvent injection rates, types of solvent, mixed solvents, well spacing and configurations etc. The major finding has been that wider lateral well spacing allow higher production rates and make the process more economic. Experimental results indicate that, under suitable conditions, the net solvent injection is about 0.2 B per B of produced oil and that high recoveries and practical rates are achievable. For example, a field prediction based on the experimental data indicates an average oil production rate of 450 B/D per horizontal well pair, 1,000 m long, drilled in a pressure-depleted, heavy-oil reservoir that is 10 m thick, to give a recovery of over 50% OOIP for a 70 acre pattern. Introduction The concept of Vapex evolves from the Steam-Assisted Gravity Drainage (SAGD) process in which two closely spaced horizontal wells are employed with steam injected from an upper horizontal injector to form a steam chamber in the formation and heated oil drains downwards, driven by gravity, to a horizontal producer located near the base of reservoir. Another form of the process involves the use of multiple vertical injection wells instead of the horizontal injector. In the Vapex process, light hydrocarbon vapors or their mixtures with non-condensible gases are employed instead of steam to extract heavy oil or bitumen from the formation. Compared to thermal processes, the Vapex process can be operated at reservoir temperature with almost no heat loss. Vapex can be used as an alternative to recover the heavy oil and bitumen from reservoirs which are not suitable for thermal processes such as reservoirs with bottom water and/or high water saturation, vertical fractures, low porosity and low thermal conductivity.

Ranking Reservoirs for Carbon Dioxide Flooding Processes

SUMMARY The screening of large number of reservoirs for the application of EOR processes has been generally done through "rules of thumb" which oftentimes fail to identify the most suitable reservoirs, due to their binary characteristics, which do not take into account synergistic effects on process performance. Therefore, a new screening method is developed in this work to rank reservoirs for carbon dioxide flooding which attempts to solve this shortcoming. The method is based on a parametric study, carried out systematically to determine the effect of reservoir properties on reservoir response to the gas injection. The study was done using a fully compositional simulator, a black oil model with a mixing parameter, and a semi-analytical predictive model. Results obtained with the three simulators are presented and compared in this paper. Reservoir parameters examined were temperature, pressure, porosity, permeability, dip, API gravity, oil saturation, net oil sand thickness, minimum miscibility pressure, saturation pressure, remaining oil in place, and reservoir depth. The optimum set of parameters which gave the best average oil production rate for a base case was obtained from the simulation studies. The base case consisted of the injection of 2000 MSCF/D of carbon dioxide in a inverted five spot, 40 acres pattern. The decrease in oil production rate with departures of the characteristic parameters from the optimum values were also determined to quantify the importance or weight of each property. Actual reservoirs were ranked by an arbitrary heuristic function, called the exponentially varying function, whose value depended exponentially on the weighted differences between the properties, characteristic of the reservoir, and the optimum values obtained from the simulation studies. Results obtained with the three simulators compare quite well and indicate that on the average, the best reservoir for carbon dioxide injection should have an oil gravity of 36°API, a temperature of 150 °F, a permeability of 300 mD, an oil saturation at the start of the injection of 60%, a reservoir pressure at the time of injection of around 200 psi over minimum miscibility pressure, a porosity of 20%, a net sand thickness of 40 ft and a reservoir dip of 20°. Of the above parameters, those whose changes around the optimum influence the most process performance are API gravity, oil saturation and reservoir pressure. Therefore, the reservoirs with these three parameters closer to the optimum values are the best candidates for CO2 injection. This is taken adequately by the exponentially varying function defined in the paper. The procedure was applied to rank about six hundred reservoirs in the greater Anaco and Oficina areas of Eastern Venezuela in order to identify the most suitables for a pilot test. The reservoir ranked 30th by the method hereby described was chosen to implement the pilot. This procedure could be easily extended to other EOR processes once the necessary simulations are carried out.

Gas Injection for Upstructure Drainage

Here are a theoretical analysis and a summary of field data on the performance of upstructure drainage projects in which gas is injected and performance of upstructure drainage projects in which gas is injected and oil is produced through the same well in a cyclical operation. It has proved to be an economical method of recovering upstructure reserves that proved to be an economical method of recovering upstructure reserves that are too small to justify additional wells. Introduction The first application of gas injection for recovery of oil located above the highest well in a reservoir was revealed to the industry in a 1954 publication by Evans and Barry, of Stanolind Oil and Gas Co. They reported that gas injection was started in Aug., 1950, into the Camerina "B" sand of their West Hackberry field in Cameron Parish, La. Limited industry acceptance of this additional recovery process was initially based upon this favorable report. A number of additional articles appeared in industry publications and the process became generally accepted for both one-well and multiwell reservoirs by mid-1960. Humble's experience with one-well gas injection projects started in the offshore and southern projects started in the offshore and southern Louisiana areas in the late 1950's. (In this study 130 of the projects were considered.) These projects have produced 3.4 million bbl of oil not economically recoverable by other means. Average gas injection requirements for all projects at depths from 4,000 to 13,500 ft have amounted to 3.1 Mscf of gas per barrel of oil recovered. Some of this gas has been produced back with the oil, and the net amount of gas left in all reservoirs is 3.1 Mscf/STB. This is expected to decline to about 2.5 Mscf/STB when all projects are depleted. Clearly it is economically attractive and good conservation practice to recover these reserves. Previous publications about one-well projects in which the same well is used for gas injection and oil production have described in detail the reservoir production have described in detail the reservoir characteristics and performance of one or two projects that generally were quite successful. There is, projects that generally were quite successful. There is, however, a notable absence of theoretical methods for estimating production rates from these projects and of field data on the performance of a large number of projects with widely varying reservoir characteristics. Our purpose here is to present theoretical guidelines and field data concerningthe maximum gas-oil segregation rate,the maximum average oil production rate,the minimum and actual gas requirements to recover one barrel of oil, andidentification of the projects that are most likely to succeed. Theory Fig. 1 shows an idealized one-well reservoir with gas being injected. The reservoir is bounded on the sides by faults, updip by salt or shale, and downdip by an oil-water contact. Although the geometry is idealized, the general situation is typical of many small, water-drive reservoirs found around piercement salt domes in southern and offshore Louisiana. The updip oil in these reservoirs is recovered by a cyclical operation with three distinct parts. First, gas is injected and migrates updip by gravity segregation. This is followed by a shut-in period in which the gas continues to migrate updip from the well. Then the well is produced until the displaced oil is recovered. JPT P. 361