论文igu2009docswgcfinal00250

1、TEMPORARY UNDERGROUND ASSOCIATED GAS STORAGES IN POROUS FORMATIONS - PROMISING TREND FOR SOLVING THE PROBLEM OF ITS UTILIZATIONA.A.Mikhailovsky, G.N.Ruban (GAZPROM VNIIGAZ)m3According to the official data, only 72% from 55 blnof total annualvolume of produced associated petroleum gas (APG), which re

2、presents a valuable feedstock of hydrocarbon and rare gases, was used in the Russian Federation in 2007. Nearly 26% of APG is processed, 46% is used by subsurface companies for the needs of oil and gas fields, while 28% is flared. Thus, rational use of associated petroleum gas is a crucial task asso

3、ciated with fulfillment of license agreements and keeping environmental legislation for the majority of oil companies.Oil-producing companies implement a set of measures adopted by the government of the Russian Federation and aimed at raising APG utilization level up to 95%.Development of the majori

4、ty of oil and gas condensate fields includes water injection to maintain formation pressure, increase of oil recovery factor (ORF) and enhancement of oil recovery from pay beds. Gas reinjection is used less frequently for these purposes 1, 2.Oil and gas fields remote from unified gas supply system a

5、nd customersveryoftenhavepoor gastransmission infrastructure. APG transmission in large capital investments for construction of gas facilities, connecting gas pipeline, which as a ruleon oil field development projects, especially at theindustrial treatmentincreasesvolumes requires units, compressori

6、nvestment “load”of new gas transmissioninitial stage, i.e. field production test. Constructionnetwork requires a long period of time - up to 5-10 years.Injection of treated APG into reservoir beds for temporary storage may become the first step towards improved APG utilization during development of

7、remote and hard-to-access oil-producing areas, which lack gas transmission systemfor direct gas supply to the consumers.1Temporary storage of associated petroleum gas may be arranged in gas reservoirs of gas condensate and oil and gas condensate fields, gas caps of oil and gas condensate fields, oil

8、 reservoirs and water-bearing beds located at the fields, which are under development, or nearby.Temporary underground associated gas storages (TUGS) require relatively small volume and tight schedule of construction and comparatively low level of investments. Most of the infrastructure facilities o

9、f temporary underground gas storage (like gas injection wells, gas pipelines, compressor facilities) can be used for the subsequent field development and gas transmission, which increases cost- efficiency of projects.Furthermore, several oil-producing companies can have shares in TUGS construction a

10、nd operation projects in one region. This allows to cut expenses for the participants of the investment project.TUGS help to increase the level of utilization of non-renewable associated petroleum gas resources, commission and effectively develop new oil and gas condensate fields without combustion

11、of APG, minimize negative environmental impact, improve environmental situation in oil and gas producing areas. This can become essential at the stage of commissioning of a new field experimental area, when TUGS can serve as a specific technical mode for development with annual oil recovery rates be

12、ing determined by APG storage capacities in terms of injection rates and volumes of temporal storage.In case low-permeable or high watercut oil reservoirs with hard-to-recover reserves of high-viscosity oils are used for APG storage, TUGS gas methods can provide additional oil recovery and increase

13、of oil recovery rates 1, 2.Gazprom VNIIGAZ has implemented a set of technological projects on APG TUGS for NK Rosneft, Lukoil and their affiliates. During the implementation process the most innovative technologies were applied and new approaches tosolving the problem of APG utilization were used.2A

14、PG TUGS are designed and constructed on the basis of technologies developed and previously tested on underground natural gas storages (UGS) in reservoir beds, including:1. Geologic, geophysical and hydrodynamic estimation of reservoir bed as a potential site for APG injection and temporary storage.2

15、. Special methods for processing the results of reservoir and drill-hole gas- hydrodynamic research.3. Forecast of injection rate and productivity of designed directional and horizontal injection and production wells using specific methods based on results of gas hydrodynamic research conducted in d

16、rilled vertical holes.4. Hydrodynamic feasibility evaluation of the best properties (length, diameter, hole angle) of directional and horizontal well completion with particular equipment and specified diameter of production tubing.5. Development of standing geological-technological models of TUGS ap

17、plying foreign and national state-of-art software packages.6. Increase of discharge pressure of compressor station and wellhead pressure, maintaining formation pressure in the storage site higher than initial field pressure or hydrostatic pressure in water-bearing beds.7. Application of methods of a

18、real and selection layer control for associated gas injection into the gas cap and oil recovery from oil-producing part of oil and gas condensate field, use of analytical and statistical methods of gas quality control in the formation.8. Cluster arrangement of TUGS designed gas injection wells. Feas

19、ibility evaluation of number of wells in a cluster.9. Construction of directional injection and production wells with horizontal bottom.10. Assessment of technological risks and required reserves for estimation of number of designed gas injection wells.11. Using drilled wells taking into account the

20、ir technical condition formonitoring and integrity control of the storage site.312. Technical and economic assessment of efficiency of the taken decision on APG injection in TUGS and assessment of project economic risks.The use of technologies of underground natural gas storage in reservoir beds for

21、 design and construction of APG TUGS is exemplified by oil and gas condensate field in East Siberia.Selection of potential site for injection and storage of associated petroleum gas is the key issue in TUGS construction and field development prospects. There were several potential sites for injectio

22、n and storage of associated petroleum gas at the field: three water-bearing beds in Cambrian limestones and dolomites, gas caps in Riphean carbonate deposits and Vendian terrigenous deposits in oil and gas condensate reservoir.It is worth mentioning that underground gas storages currently available

23、in Russia and the CIS are located in terrigenous water-bearing beds or in gas deposits of terrigenous and reef carbonate reservoirs. There is no experience of UGS construction in water-bearing carbonate reservoirs.Hydrodynamic calculations of associated gas injection into Cambrian water- bearing bed

24、s proved that trap efficiency coefficient was expected to be not higher than 0.3-0.4, and its capacity would not provide required volumes for gas storage under highly uneven distribution of injected gas in fractured reservoirs and low- amplitude trap (amplitude 25m with area 513 km2). Moreover, unde

25、r such geologic hydrodynamic conditions extraction ratio of the injected gas is expected to be low not exceeding 0.3 - 0.4.Water-bearing beds are underexplored. Exploration drilling and a set of geologic, geophysical and full-scale hydrodynamic surveys are required for their additional prospecting.

26、This will result in longer schedule and higher cost of TUGS construction.Riphean and Vendian deposits are located in the biggest oil and gasreservoirs of the field capable of storing associated gas, providing safety and full extraction of the injected volumes of gas. These deposits are characterized

27、 by the4best permeability and porosity properties, while gas caps ensure enough fluid resistivity both for hydrocarbon and rare gases.Comparative geologic and geophysical analysis 3 as well as hydrodynamic calculations confirmed the choice of Riphean gas-bearing deposits as a site for injection and

28、temporary storage of APG. A number of mentioned reasons does not allow to recommend Cambrian water-bearing layers to be alternative for TUGS purposes.Processing results of gas hydrodynamic surveys of formations and drilled wells. It is well-known that the best way to identify filtration properties o

29、f the formation and bottom-hole zones is to process results of gas hydrodynamic surveys of the wells drilled at the field. Due to the limited volume and low quality of conducted surveys of exploration wells at the site selected for gas storage, standard methods of data processing were insufficient.

30、Satisfactory results were delivered by means of special processing methods for these surveys, including influence function 4.Forecast for injection capacity of designed wells can be done on the basis ofmodel calculations with specified values of permeability and reservoir and wells. More reliable ev

31、aluation with account ofproperties can be based on parameters identified upon theporosity of the actual reservoirresultsof gashydrodynamic surveys of drilled wells 5, 6. Flow coefficients of the TUGS designed wells were estimated according to the method developed in Gazprom VNIIGAZ. This method cons

32、ists in “recalculation” of these coefficients from drilled vertical holes to designed horizontal holes. It also provides modification of mentioned coefficients for vertical holes in case of changing completion interval and diameter, “recalculation” of modified coefficients of vertical wells for vari

33、ous lengths and diameters of horizontal bottom of a designed well, specification of individual coefficients for designed wells taking into account permeability and porosity properties of the cells of formation permeability model.Several construction options for designed injection wells were reviewed

34、: withproduction tubing (PT) diameter 114mm and 127mm, horizontal bottom length5from 200m to 800m with 100m spacing. Results coefficients for two main construction options for presented in table 1.Hydrodynamicfeasibilityevaluation ofof “recalculation” of flowmedium designed well arethe bestlength,di

35、ameter ofhorizontal part and production tubing of designed wells was conducted on the basis of developed methods with minimal pressure loss criteria 5. An optimal length of horizontal completion was estimated at 400m, drilling bit completion diameter - 145mm, tubing diameter and diameter of tail fil

36、ter, which the wells are equipped with - 114mm.Standing geologic-technologic model of TUGS. Design of associated gasinjection and storage system, analysis and adjustment of parameters of this systemwere carried out on the basis of integrated modelling principles 7.Table 1Flow coefficients of designe

37、d wellsandcontinuousgashydrodynamic6PTdiameter, mmDrilling bit completi on diameter, mmPenetra tion length, mCoefficient of resistance in PT,(kgs/cm2)/ (thous.m3/day)2Flow coefficientsCluster 1Cluster 2,(kgs/cm2)/ (thous.m3/da y),(kgs/cm2)/ (thous.m3/day)2,(kgs/cm2)2/ (thous.m3/da y),(kgs/cm2)/ (tho

38、us.m3/day)2Medium existing vertical well10219025,60,02566,50,538Medium fully penetrated well102190700,02524,30,072Medium designed gas injection horizontal well1141454000,0206,30,0035,7870,0031141455000,0205,30,0024,7950,0021271454000,0126,30,0035,7870,0031271455000,0125,30,0024,7950,002This approach

39、 is implemented by means of standing geologic-technological model, which includes targeted geological model of storage site, hierarchic complex of adapted filtration mathematical models of formation and well system, stationary gas dynamic model of gas motion in the wells and surface gas pipeline sys

40、tem of TUGS. Detailed geological model and 3D filtration model of dual- porosity system provided by subsurface user were made in PETREL and ECLIPSE software. Filtration mathematical model of well system, 2D areal model of gas cap and stationary gas dynamic model were prepared on the basis of Gazprom

41、 VNIIGAZ in-house design in special software environment.Increase of gas injection pressure can not exceed initial formation pressure, as there is a risk of destroying integrity of reservoir cap. Vendian silt-argillaceous deposits are the cap for Riphean reservoir bed, which is the storage site. TUG

42、S maximum permissible formation pressure was assessed with the help of 8, 9 taking into account the similar sites and long experience in design and construction of UGS in reservoir beds. The following initial data were used in calculations. Occurrence depth of reservoir top 2275m. Thickness ratio of

43、 reservoir bed to sealing (cap) layer 5:1. Density of the sealing rock layer - 2.75 kg/m3, Poissons constant 0.28. Maximum permissible formation overpressure at TUGS as compared to initial field pressure is estimated at about 28%. According to the existing experience, obtained formation overpressure

44、 value for specified initial data under mining and geological conditions of the considered storage site has a certain margin.Technology of increasing compressor station injection pressure will allow to inject and store required volumes of APG, increase wellhead pressure during injection up to 25 MPa

45、, raise design capacity of gas injection wells in average up to 1.3 mln.m3/day and restrict their number up to 5 at the first stage, and 14 at the second stage of TUGS operation.Areal and selection layer control for gas injection in reservoir bed. Atdesigned TUGS, storage site is represented by cave

46、rnous fractured reservoirs with mostly (81%) sub-vertical direction of incipient cracks. Nearly 73% of oil pool7space is situated in sub-gas zone. Under such conditions breakthrough of free gas and “gas contamination” of wells become one of the main factors that limit production rate of oil wells.In

47、 order to decrease breakthroughs of free gas to oil production wells, model calculations on areal and selection layer control of associated gas injection into the gas cap and oil recovery (with maintaining formation pressure by water injection into oil-bearing reservoir beginning from 2017) have bee

48、n made. For this purpose designed clusters of gas injection wells are placed in north-western and northern parts of gas cap remote from prior oil recovery zone. These areas are characterized by low fracturing and the highest gas saturated thickness reaching 70m. Designed horizontal bottom structures

49、 of gas injection wells are situated in the near-top part of gas cap, 50m higher than initial gas-water contact.According to the recommended option of oil formation development with APG circuiting, Table 2 shows annual changes in volumes of oil recovery, water injection, APG production and injection

50、 into the gas cap (storage site) with account of gas consumption for own technological needs (approximately 330 mlmn.3 per year). Figure 1 represents dynamics of formation pressure in cluster zone and on the top of reservoir bed above cluster of gas injection wells, dynamics of bottom- hole and well

51、head pressures at the end of each year.Table 2Annual changes in volumes of oil recovery, water injection, APG production and injection in the storage site8YearOil recovery, thous. m3Water injection, thous. m3APG recovery, mln m3APGconsumption forin-house needs, mln m3APGinjection, mln m3TotalIncludi

52、ngFreedissolved20123201014439794642801162201327350204916723772431807201425530255522103452662288201524610268123513313262355201628470301126253853312680201725331314303026963343302700201827982300344430833613303114Comparative analysis of scenarios with and without APG injection in said period of TUGS ope

53、ration confirms that during the first 6 years suggested APG injection technology will not lead to significant activation of gas-water contact movement towards oil pool and will not critically influence the oil formation development. Formation pressure in cluster area and on reservoir bed top above c

54、luster of gas-injection wells does not exceed maximum permissible pressure. In case maximum gas factor is set at 1500 m3/m3, by the end of the first 6 years of development and according to the scenario with APG injection, the number of decommissioned production wells of the active stock will be 8-10

55、% higher than in scenario without APG injection. It is recommended not to place 5 designed production wells in sub-gas zone in the area of APG injection during drilling outan oil formation.31,030,029,028,027,026,025,024,023,022,021,020,019,018,020122013 2014 201520162017 20182019 2020 2021 2022 2023

56、YearsFormation Wellhead Max.p.ermissibleBottom-hole Onthetopabove cluster9Pressure,M, Pa201930464763356731723953303237201029765765376833903783313437202129368228354431683753303214202228918274312227443783302792202327158656305227003523302722Figure 1. Dynamics of formation pressure in cluster zone and on the top of reservoir bed above cluster of gas injection wells, dynamics of bottom-hole and wellhead pressures at the end of each year.According to calculations, gas injecti