High Gas-oil Ratio Research Articles

ASSOCIATED ANNULAR GAS UTILIZATION METHODS

The article discusses the influence of annular associated petroleum gas (APG) pressure on the performance of a bore-hole sucker rod pump. It is known that gas separators are used in wells with a high gas-oil ratio, but they do not completely solve the issues of negative impact of APG on the flow, reliability and dynamics of bore-hole pumps. Separated APG accumulates in the annulus, increasing the pressure in it slightly more than the pressure in the gathering manifold. This opens the wellhead valve, and the gas partially flows into the manifold, reducing the pressure in the annulus to the pressure in the manifold and the valve closes. In this case, the pressure in the annulus will always be slightly greater or equal to the pressure in the manifold, which in some cases reaches 4.0 MPa. The effect of this pressure leads to the release of the flowing level and the reduction of the liquid layer over the pump suction and in the extreme case of gas breakthrough into the pump cavity with subsequent jamming of the plunger pair. In this regard, it raises the challenge, firstly, to reduce the pressure of the annular gas and, secondly, to utilize this gas. In this regard, experience in using methods for utilization of annular APG and devices for reducing annular gas pressure are considered. The scheme of a mobile unit for collecting annular APG and subsequent disposal in an oil-gathering main is proposed. A method for calculating the frequency and volumes of utilization of the well, depending on the gas factor and the water cutting of the well production is given. The advantages of a suspended compressor using the energy of an unbalanced sucker string for injecting gas into a manifold are shown.

Carbon capture and adjustment of water and hydrocarbon dew-points via absorption with ionic liquid [Bmim][NTf2] in offshore processing of CO2-rich natural gas

Offshore oil production from huge reservoirs at deep waters with high gas-oil ratio and high carbon dioxide (CO2) content is a challenging puzzle because oil extraction imposes to process a huge flow rate of raw CO2-rich natural gas from which CO2 must be separated and sent to appropriate destination. Offshore gas processing comprises three steps: water dew-point adjustment (WDPA), hydrocarbon dew-point adjustment (HCDPA) and CO2 removal to avoid transport of inert and to boost oil production by injecting CO2 into the reservoir for enhanced oil recovery. In offshore rigs, gas is conventionally treated via TEG absorption for WDPA, Joule-Thomson expansion for HCDPA and membrane permeation for CO2 removal. This work discloses a new concept of CO2-rich natural gas processing using the ionic-liquid [Bmim][NTf2] for simultaneous WDPA, HCDPA and CO2 removal. All results were obtained via rigorous simulations, including the ionic-liquid implications in vapor-liquid equilibrium and heat-effects. The main novelty of the new process is its high-pressure selective stripping of CO2, lowering compression power for enhanced oil recovery utilization. Economic comparison of conventional gas processing with the ionic-liquid gas processing shows that the latter has 19.3% higher revenues, 23.6% less manufacturing costs and 18% less investment, entailing a 37% higher net present value.

Energy optimization of an FPSO operating in the Brazilian Pre-salt region

FPSO (Floating, Production, Storage and Offloading) units are used for primary petroleum processing. The FPSO units have a technical advantage for short-lived well exploration and for remote marginal fields, where building a pipeline is cost-prohibitive. Considering the relevance of the FPSOs for the Brazilian petroleum market, the main goal of this paper is to present an optimization procedure to find the best operating conditions of a primary petroleum platform processing crude oil with high gas-oil ratio (GOR) and moderate CO2 content. Seven input parameters related to operating pressures of plant are selected for the optimization procedure aiming to minimize the total fuel consumption (FUE) of the FPSO. For the optimization procedure, the processing plant of the FPSO is modeled and simulated by using Aspen HYSYS®, and the Genetic Algorithm is used for minimizing the objective function. The optimum operating condition found by the optimization procedure presented a reduction in fuel consumption by 4.6% when compared to a conventional operating condition. Moreover, because of the fuel consumption optimization, a significant reduction by 6.3% in the power consumption of the plant and an improvement in the recovery of the volatile components were verified, in comparison with the baseline case.

Integrated CO2-Foam Pilot in a Heterogeneous Carbonate Field

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 190204, “An Integrated CO2 Foam EOR Pilot Program With Combined CCUS in an Onshore Texas Heterogeneous Carbonate Field,” by Z.P. Alcorn, SPE, and S.B. Frederiksen, University of Bergen; M. Sharma, University of Stavanger; A.U. Rognmo, SPE, University of Bergen; T.L. Føyen, SPE, University of Bergen and SINTEF; and M.A. Fernø, SPE, and A. Graue, SPE, University of Bergen, prepared for the 2018 SPE Improved Oil Recovery Conference, Tulsa, 14–18 April. The paper has not been peer reviewed. A carbon-dioxide (CO2) -foam enhanced-oil-recovery (EOR) pilot research program has been initiated to advance the technology of CO2 foam for mobility control in a heterogeneous carbonate reservoir. Previous field tests with CO2 foam report varying results because of injectivity problems and the difficulty of attributing fluid displacement specifically to CO2 foam. A more-integrated multiscale methodology was required for project design to further understand the connection between laboratory- and field-scale displacement mechanisms. East Seminole Field The East Seminole Field in the Permian Basin of West Texas was discovered in the early 1940s with an estimated 38 million barrels of original oil in place (OOIP). The field was developed throughout the 1960s, producing 12% OOIP through pressure depletion. Water floods began in the early 1970s and continued into the 1980s with strategic infill drilling, reducing the well spacing from 40 to 20 acres. Tertiary CO2 floods began in inverted 40-acre, five-spot patterns in 2013 in the eastern portion of the field. Miscible CO2 injection initially increased oil production and reservoir pressure. However, rapid CO2 breakthrough, high producing gas/oil ratio (GOR), and CO2 channeling was soon observed in peripheral production wells. CO2 performance suffers because of reservoir heterogeneity and unfavorable mobility ratios between injected CO2 and reservoir fluids, resulting in poor areal sweep efficiency, high producing GOR, and CO2 channeling. As seen in other areas of the Permian Basin, tilted fluid contacts, presumably resulting from basin activity or a breach of seal, have created a deeper residual oil zone (ROZ). These zones are thought to have been naturally waterflooded through hydrodynamic dis-placement and have been shown to contain considerable immobile oil (20 to 40% OOIP) that can be mobilized by CO2 flood. Thus, the residual oil saturation in the ROZ is similar to waterflooded zones and establishes it as an economically attractive target for tertiary CO2 recovery efforts.

Determination of reasonable water injection timing for complex fault block high saturation reservoir - A case study of C30 fault block in Chaheji oilfield

High saturation reservoir has the characteristics of high gas-oil ratio, high saturation pressure and low difference between reservoir pressure and saturation pressure. In the process of development, the oil layer is very easy to degas due to the lag of water injection, which affects the production of oil well. Therefore, it is necessary to determine reasonable water injection timing and timely water injection to ensure the efficient development of high saturation reservoir. Based on the characteristics of complex fault block high saturation reservoir, the reasonable water injection timing of high saturation reservoir is determined by means of the combination of the finite layer quasi-steady state well test method and the material balance method. Through the actual production data verification, the calculation results of two methods are approximate, and the accuracy is high enough to meet the production need. The determination method is suitable for the reasonable injection timing of high saturation reservoir.

Origin of natural gas in Jurassic Da'anzhai Member in the western part of central Sichuan Basin, China

The distribution pattern of oil and gas in the western part of central Sichuan Basin is complicated, there are many different views on the sources of natural gas, which restrict further exploration and deployment of oilfields. Therefore, by analyzing geochemical characteristics and quantitative calculation of natural gas in study area, combined with the data of structure and gas-oil ratio, the origin and sources of gas are discussed and analyzed. The results show that the dryness coefficient of the natural gas ranges between 0.71 ∼ 0.93, δ13C values range between −45.3 ∼ −38.0‰ in methane, −32.0 ∼ −25.6‰ in ethane and −30.0 ∼ −25.3‰ in propane. Crossplots of isotope data and quantitative calculation indicate that natural gas in Da'anzhai Member is characterized by the mixture of sapropelic and humic natural gas, the humic gas largely occupies the proportion of 20–40%, up to 70%. It is the result of upward migration of natural gas in Triassic Xujiahe Formation. The abnormally high gas-oil ratio is an important manifestation of this upward intrusion. Based on the study of high gas-oil ratio wells, the distribution of humic natural gas that intruded from Xujiahe Formation and enriched in Da'anzhai Member is unevenly distributed. It inherits characteristics of “Plaque accumulation” of natural gas in Xujiahe Formation. The inhomogeneity of this plane distribution is controlled by fault location, fault scale and the size of underlying Xujiahe Formation gas reservoirs. The humic gas from Xujiahe Formation occupies a large proportion in blocks of Da'anzhai Member which are favorable for intrusion, accumulation and preservation of Xujiahe Formation natural gas, whereas for blocks without these conditions, natural gas is often associated gas.

The Experimental Study on the Flooding Regularities of Various CO2 Flooding Modes Implemented on Ultralow Permeability Cores

The application of water flooding is not successful for the development of low permeability reservoirs due to the fine pore sizes and the difficulty of water injection operation. CO2 can dissolve readily in crude oil and highly improve the mobility of crude oil, which makes CO2 flooding an effective way to the development of the ultralow-permeability reservoirs. The regularities of various CO2 displacement methods were studied via experiments implemented on cores from Chang 8 Formation of Honghe Oilfield. The results show that CO2 miscible displacement has the minimum displacement differential pressure and the maximum oil recovery; CO2-alternating-water miscible flooding has lower oil recovery, higher drive pressure, and relatively lower gas-oil ratio; water flooding has the minimum oil recovery and the maximum driving pressure. A large amount of oil still can be produced under a high gas-oil ratio condition through CO2 displacement method. This fact proves that the increase of gas-oil ratio is caused by the production of dissolved CO2 in oil rather than the free gas breakthrough. At the initial stage of CO2 injection, CO2 does not improve the oil recovery immediately. As the injection continues, the oil recovery can be improved rapidly. This phenomenon suggests that when CO2 displacement is performed at high water cut period, the water cut does not decrease immediately and will remain high for a period of time, then a rapid decline of water cut and increase of oil production can be observed.

The Niobrara formation in the Southern Powder river basin, Wyoming: An emerging giant continuous petroleum accumulation

The Niobrara Total Petroleum System (TPS) covers an extensive area across the Rocky Mountain Region, US. In the Powder River Basin (PRB), the petroleum system consists of source beds in the Upper Cretaceous Niobrara Formation as well as reservoirs in the Upper Cretaceous Frontier, Turner, Niobrara, Sussex, Shannon, Parkman, Teapot, and Teckla. The Niobrara is a deep-water hemipelagic carbonate mudrock and is Coniacian to early Campanian in age and approximately 150-650 ft thick. The formation, where productive, has low porosity (< 10%), low permeability (<0.01 md), and pore throat sizes less than 0.1 micron. The immature-mature present-day depth boundary is approximately 8000 ft. The formation is subdivided informally into three units in the PRB (A, B, and C). The units consist of cycles of marls and chalks. Geologic factors related to successful exploration and development include excellent source-rock quality, source-rock maturity, reservoir thickness, matrix and fracture porosity and permeability development, high geothermal gradients, overpressure, oil gravity, gas-oil ratios, and regional fracture development. The accumulation covers a large area and is a potential giant accumulation. Recent drilling success by several operators indicates that productive reservoir conditions exist in the southern PRB (Figure 1). In this area, the Niobrara Formation consists of three marly chalk facies, informally referred to in descending order as A, B, and C benches that are separated by marls, similar to the Denver Basin (Figure 2). The basal Fort Hays Member of the Niobrara Formation is absent in the southern PRB (Weimer and Flexer, 1985; Taylor, 2012). The main reservoir target currently in the southern PRB is the Niobrara B chalk/marl interval. Porosities are 6-12% and permeabilities are less than 0.01 mD (Taylor, 2012). Hydrocarbons are generated from mainly a marine type II kerogen with total organic carbon content (TOC) averaging 2-3 wt.% for the interstratified organic-rich source beds (Anna, 2009).

Повышение эффективности и снижение издержек эксплуатации УЭЦН в скважинах с высоким газовым фактором

Повышение эффективности и снижение издержек эксплуатации УЭЦН в скважинах с высоким газовым фактором

Formation characteristics and resource potential of Jurassic tight oil in Sichuan Basin

Through test analysis of large amount of cores, rock fragments and crude oil samples, and in combination with dynamic data of production from 456 oil wells, hydrocarbon generation potentials of four major source rocks and accumulation characteristics of three major pay layers in the Jurassic of Sichun Basin were well investigated. Results indicated that source rocks in the Lianggaoshan Formation, the Da'anzhai Member and the Dongyuemiao Member mainly generated oil, and those in the Zhenzhuchong Member dominantly generated gas; the organic-rich source rocks controlled distribution of sweet spots of tight oil, and most industrial oil wells were located at the area with high-quality source rocks (TOC > 1.2%); and micron-sized pore throats were effective storage space, and fractures played a key role in initial high yield. Jurassic tight oil in the Sichuan Basin was characterized by light oil, high gas-oil ratio and abnormal high pressure, which were favorable for tight oil flow and output. Four methods (i.e., small bin method, resource abundance analogy method, EUR analogy method and total organic carbon method) were used to estimate Jurassic oil in-place in the Sichuan Basin which ranged from 2 × l09 to 3 × l09 t. Through analysis of main controlling factors of resource enrichment, the grading criteria were established for the evaluation of oil in-place in the Sichuan Basin. Through the small bin method, the oil in-place of Type I, Type II and Type III was 1.611 × l09 t, 0.477 × l09 t and 0.289 × l09 t, respectively. It was predicted that the largest exploration potential of the Da'anzhai Member was in the Nanchong-Suining area and the east of Liangping area, the most favorable exploration area of the Lianggaoshan Formation was in the Guang'an-Nanchong-Suining-Yilong area, and the good exploration prospect of the Dongyuemiao Member was in the south of the Guang'an-Suining area.

New insights into the formation mechanism of high hydrogen sulfide–bearing gas condensates: Case study of Lower Ordovician dolomite reservoirs in the Tazhong uplift, Tarim Basin

Huge, high gas–oil ratio, hydrogen sulfide (H2S)-bearing gas condensate accumulations were recently discovered in the Ordovician carbonate reservoirs of the Tazhong uplift in the Tarim Basin, northwest China. Distinct differences exist between the eastern and western condensates in terms of chemical and isotopic compositions. Condensates from the western part of the uplift were characterized by high dibenzothiophenes (generally >500 μg/g), a high H2S concentration (∼7%, vol./vol.), and relatively depleted 13C methane (δ13C1 = −55.5‰ to −36‰). The H2S concentration in the Tazhong gas condensates shows a positive correlation to Mg2+ concentration in the formation water. Formation water in Lower Ordovician–Cambrian strata in the Tazhong uplift is rich in Mg2+, which facilitates the thermochemical sulfate reduction (TSR) of sulfate contact ion pairs (CIPs) to produce H2S and dibenzothiophenes. A detailed comparison of the chemical compositions of the formation waters in different strata indicates that a high H2S concentration in the Tazhong gas condensates originates from the TSR of sulfate CIPs in the Lower Ordovician–Cambrian strata, where a primary oil accumulation may have existed. The concentrations of 3- and 4-methyldiamantanes in the western condensates (80 to 150 μg/g) are relatively lower than those from the eastern part of the uplift. Also, the δ13C1 in the western H2S-bearing gas condensates was more negative, and the δ13C2 − δ13C1 value was larger than that from typical TSR-altered gases. These features indicate that the western Tazhong samples had just entered the initial stage of TSR. According to the pressure, volume, temperature (PVT) phase diagram, the lower Paleozoic section was quickly buried after the Tortonian. High-H2S hydrocarbon inclusions formed during the last 10 m.y. when paleotemperatures reached 140°C (284°F). Because the reaction rate of the sulfate CIPs oxidation was relatively slower than that of H2S autocatalysis during the entire TSR process, advanced TSR has not been accomplished yet. It is also inferred that the Tortonian was the key period for accumulation of secondary H2S-bearing gas condensates, resulting from abundant gas washing along deep fractures and charging in the early reservoirs. An increased aromaticity parameter (toluene/n-heptane) and an increased fractionation index from east to west indicate an intensified degree of gas washing. Different gas-washing intensities in the eastern and western gas condensates led to diverse PVT states as well. Deep strata in the Tazhong uplift were characterized by multiple charges and mixing, coupled with periodic TSR, leading to the occurrence of variable H2S-bearing gas condensates.

STUDY OF COMPOSITIONS FOR KILLING OF OIL WELLS HAVINGA HIGH GAS-OIL RATIO

Based on the laboratory studies results the advantages and limitations of well killing fluids are discussed. The results showed that neither of the studied fluids is applicable for killing the oil wells with a high gas-oil ratio in the field Novoportovskoye. For this field a new well killing fluid composition has been developed that differs from currently used fluids (the new composition is prepared for a claim on invention). The components of the developed formulation are widely available and are of low cost.

Analysis of Natural Gas Production in Pre-Salt via Pipelines with MEG and Onshore Processing

The exploration of pre-salt introduces challenges beyond those posed by ultra-deep waters and the thick of carbonaceous reservoirs. Among the main difficulties are the high gas-oil ratio and the high content of carbon dioxide (CO2) present in the gas. This paper proposes an alternative to the technology currently used in the exploration of pre-salt, in which the gas is treated on the platform. The proposed alternative is applicable to reservoirs which CO2 concentration in gas is greater than 50%, like Jupiter that contains 79% of CO2. For this scenario is suggested that exploration occurs in three production areas: subsea, offshore and onshore. The proposed technology includes the construction of three subsea pipelines: one for the transportation of untreated gas (that is treated onshore); a second for the return of the recovered hydrate inhibitor (in order to be re-injected into the gas pipe) and the last for the return of the carbon dioxide stream separated from the gas.

Study of Properties of a Dispersant Used for Extracting Oil with High Gas-Oil Ratio

The article presents the bench test results for a dispersant manufactured by Izhnefteplast Company, which specializes in batch production of unique submersible pumping equipment for oil extraction. The submersible equipment is unique in that the working elements of the pumping equipment are made of polymeric materials unlike the conventional concept of pumping machinery for oil production. The relevance of the bench tests is determined by the fact that submersible pumping equipment faces the problem of pumping out well products containing a good deal of free gas in actual field conditions. Gubkin Russian State University of Oil and Gas has provided background to carry out bench tests of submersible pump equipment operating on model gas-fluid mixtures at various input conditions (pressure, temperature, electric motor shaft speed, feed, etc.). The bench testing is aimed at development of a procedure for dispersing efficiency determination in pre-start operation modes of submersible electrical centrifugal pumps for oil extraction.

Petroleum geochemistry of the Sea Lion Field, North Falkland Basin

The Sea Lion Field, lying approximately 220 km north of the Falkland Islands in the northern rift of the North Falkland Basin, contains waxy oil in Lower Cretaceous reservoir sands. The oil is likely to be sourced from Lower Cretaceous lacustrine source rocks lying beneath the reservoir sands. A significant complication in interpreting the geochemical data for the Sea Lion oils comes from their overprinting by leaching of bitumen components (especially biomarkers) from immature organic-rich claystones that are interbedded with the reservoir. Accordingly, best estimates of maturity are obtained from gasoline-range and aromatic hydrocarbons. A higher maturity charge is seen in oils from some of the more western wells, consistent with their higher gas–oil ratios. Basin modelling has shown that the source rocks are more mature to the south of the Sea Lion Field, and the observed differences in oil maturity can be related to sourcing from different parts of this kitchen area and/or different stratigraphic intervals of the source-rock package. Gasoline-range hydrocarbons provide evidence for phase fractionation, with some oils having lost a more volatile fraction whilst others have received additional gas charge. A gas leg in the Beverley and Casper South reservoirs in Well 14/15-4Z appears to have been the original fluid charge, and has not displaced oil, although gas compositions suggest that gas was co-generated with oil, and subsequently separated into two phases, at least in some parts of the field.

Deepwater Gas-Zone Shutoffs With Wireline in Openhole-Gravel-Pack Completions

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 170789, “Deepwater Gas-Zone Shutoffs With Wireline in Openhole- Gravel-Pack Completions,” by Claudia Zettner, Hank Bensmiller, and Tom Lane, ExxonMobil, prepared for the 2014 SPE Annual Technical Conference and Exhibition, Amsterdam, 27–29 October. The paper has not been peer reviewed. An operator successfully executed two wireline through-tubing gas-shutoff (GSO) workovers in high-angle openhole-gravel-pack (OHGP) completions to isolate high-gas/ oil-ratio (HGOR) zones, resulting in significantly increased oil production. This paper summarizes the GSO concept, completion modeling, job planning, completion-equipment testing, job execution, and production results from one of these two wells (the processes and results associated with the second well are detailed in the complete paper). Introduction All producers in the field of study were drilled from a 36-slot tension-leg platform (TLP) at a water depth of just over 1000 m. OHGPs are the preferred completion option in this field. It was recognized during the project-design phase that controlling unwanted gas and water in the future would be challenging. The well-work solution proposed and described in this paper can address that challenge by providing lower-GOR oil and additional reserves recovery. Although the long-term depletion plans for most reservoirs in the field rely on waterflooding, some producing reservoirs have been used to store surplus gas until gas-export facilities were operational. As these injected gas caps expanded toward producers, GORs increased to the point at which processing facilities were gas constrained. Producer-well seriatims made on the basis of GOR are used to optimize oil production. The highest- GOR wells are typically cycled to manage GORs and then shut in when cycling is no longer effective. Engineering principles and field experience have shown that gas breakthrough in any zone in a well can affect overall production significantly. High gas mobility, coupled with good injection support in the gas-producing interval, can result in an HGOR, and thus a noncompetitive, producer. The completion diagram in Fig. 1 illustrates the general design of the lower completion. External shunt tubes prevented external casing packers (ECPs) on early wells. Later wells have internal shunt tubes that allow ECPs in the gravel-packed section of the well. Completions include gravel packs to minimize sand production from the unconsolidated reservoirs. Gravel-pack screens are shunted to help ensure gravel is transported and placed along the length of the screen. Gravel placement is generally effective, and sand production is rarely a problem in this field. Oil producers are directionally drilled because most reservoir objectives are not directly underneath the TLP. Reservoir penetrations are often at a high angle from vertical to provide the permeability thickness necessary to deliver target rates.

Key techniques of reservoir engineering and injection–production process for CO2 flooding in China's SINOPEC Shengli Oilfield

This paper addresses the geological problems and engineering hot points of the CO2 flooding, such as the big vertical span of the beach-bar sand, the strong reservoir heterogeneity, the distribution of residual oil, and the problem of gas channeling. The core identification, log analysis, seismic interpretation, laboratory test and numerical simulation of reservoir engineering are integrated to investigate the geological characteristics of the reservoir in the demonstration zone of SINOPEC Shengli Oilfield. It demonstrates the reservoir is large but it has thin thickness, low porosity and super-low permeability. Due to some great differences between the beach sand and the bar sand, the oil reservoirs of demonstration zone are divided into 2 sand groups, 8 small layers, and 17 sand bodies in total. Then, a 3D geological model and qualitative evaluation system of safety of vertical faults are built. The optimal evaluation method of CO2 flooding and sequestration is established. According to the engineering optimization of the CO2 flooding, the results of a recommendation scheme indicate that the enhance oil recovery can increase by 6.7%, the total injection volume is expected to reach to 563×104t, and CO2 sequestration rate is 60.5%. Finally, the multi-level umbrella downhole gas separator is designed, and the high gas–oil ratio (GOR) production string and free kill gas injection string are also successfully developed for the CO2-EOR.

Modeling Water Saturation Points in Natural Gas Streams Containing CO2 and H2S—Comparisons with Different Equations of State

Since the discovery of the Pre-Salt layer in Brazilian waters, production of high gas–oil ratio (GOR) has increased considerably. This gas has a high content of water, CO2, and sometimes H2S. A study in different conditions was conducted using several equations of state (EoS) such as Peng–Robinson, GERG-modified Peng–Robinson (PR-ISO-04), Soave–Redlich–Kwong, and Cubic Plus Association (CPA). Petrobras’ Process Simulator has been used to perform the phase equilibrium calculations. All the EoS except for CPA used parameters from the literature. A new parameter estimation procedure for CPA has been proposed using a particle swarm optimization algorithm followed by the SIMPLEX method presenting themselves together as an optimal approach. The results show that PR-ISO-04 can be considered to be an improvement compared to the original Peng–Robinson but CPA appears to be the most promising approach to be used for predicting dew points for water-containing mixtures, especially at high pressures.

Application of OIL-GAS Mixting Trasportation Process in Flat 53-13 well Group

Through the flat 53-13 well group oil and gas mixed transportation test, the gathering radius increases from 3Km to 5km, to realize the full closed gathering. Reducing electricity consumption, according to the existing problems in the mixed transportation technology are discussed, for intermittent oil and high gas oil ratio well area, a station for reference.

The Development and Technology Policy for a Gas Cap and Edge Water Reservoir with Narrow Oil Ring

Reservoir with gas cap, edge water is complex. And the oil-water and oil-gas interface will seriously influence the performance. Once out of control, gas and water invasion may occur, then oil productivity will fall sharply and oil recovery will become low. In addition, the oil penetrating into gas cap would lead to oil loss. So, the controlling methods are crucial. In this paper, we study the productive characteristics of a certain reservoir with gas cap, edge water and narrow oil ring. For the phenomenon several productive wells appeared gas breakthrough and water invasion after putting into production, this paper puts up a strategy shutting in high gas-oil ratio wells and blocking off gas breakthrough layers that proved effective. At the same time, adjusting oil and gas distribution underground by gas-water alternate also be proved practicable.