CC BY
7ТЕХНИЧЕСКИЕ НАУКИ
Deryaev Annaguly Rejepovich
Candidate of Technical Sciences, Senior Researcher, Scientific Research Institute of Natural Gas of the State Concern „ Turkmengas ",
Ashgabat, Turkmenistan
JUSTIFICATION OF THE ADOPTED METHODOLOGY FOR FORECASTING TECHNOLOGICAL DEVELOPMENT INDICATORS FOR GAS CONDENSATE FIELD DURING DEVELOPMENT BY
THE METHOD OF DUAL COMPLETION
Abstract: In the article the author provides justifications for the adoption of a methodology for forecasting technological indicators of development, standards of capital investments and operating costs adopted for calculating gas condensate field during development by the method of dual completion (DC). With an DC of two...after three layers, they are isolated from each other and a corresponding number of tubing columns descend into the well. As a result, separate development of layers is provided. Thus, the operation of each reservoir does not affect the nature of the operation of others. And in each formation, it is possible to conduct the necessary research and maintain a given operating mode.
The author focuses on the fact that the positive effect of the use of DC technology is expressed in a reduction in capital investments for the construction of wells for each of the operational facilities, operating costs and the development period of a multi-layer field, as well as in an increase in hydrocarbon production and the term of final condensate recovery with cost-effective well operation. The use of this technology contributes to an increase in the utilization rate of downhole equipment and the reliability of the downhole installation
This work can be useful for specialists in oil and gas management activities.
Key words: legal area of field, gas condensate horizons, condensate recovery coefficient, gas density, liquid flow rate.
The determination of well operation parameters and the forecast of development indicators was carried out on the basis of reserves of gas condensate horizons and areas for which the presence of oil rims was not detected. It should be noted that there are a number of uncertainties in the estimation of individual parameters for the field that can affect the accuracy of the final calculation results. The main ones are:
- the degree of activity of the legal area of field and the prediction of its impact on the dynamics of drainage regimes in the future;
- insufficient number of measurements of reservoir pressure, the inability to establish a pattern of its change over time for most horizons;
- insufficient number of definitions of filtration parameters "a" and "b" to average them across individual development objects;
- a small number of experimental determinations of the condensate recovery coefficient.
To maximize the use of available data on reservoir pressure measurements and to approximate the results of the forecast of reservoir pressure dynamics to real conditions, the following methodological technique was used.
Based on the analysis of field data using available practical data on reservoir pressure measurements for horizons, a graph of reservoir pressure changes from accumulated gas extraction is constructed in dimensionless form (Fig. 1):
Р
form- f (Qg)
(1)
P form- the ratio of the current value of reservoir pressure to its initial value;
Q - the ratio of accumulated gas extraction to its initial recoverable reserves.
When determining the initial recoverable gas reserves, the expected final gas recovery coefficient of 0.85 was adopted.
When constructing these graphs, it was taken into account that the drainage regime of the gas condensate field of the Korpedje field, as well as other field in the region, is mixed. According to the experience of the development of gas condensate field in Western Turkmenistan, it is known that during their operation, along with the gas regime, the pressure of marginal and plantar waters also appears, and its share increases over time [1].
Therefore, at the end of the development of field, a significant amount of pressure remains in the formations. In most cases, the value of the final reservoir pressure is 10-30% of its initial value.
In the calculations, the differential condensate isotherms in reservoir conditions given in [2, 3] were used. These data were previously processed by polynomials for the convenience of performing calculations on a computer.
Estimated calculations of the parameters of the DC of a gas condensate well were performed for the case of lifting the production of two layers in one column (see the diagram in Fig. 2), which corresponds to the use of a complex of downhole equipment of the KSG type.
The calculation sequence is as follows.
1. The annual and accumulated gas production, as well as the average flow rate of gas wells (qi) for the future for the option of developing it by an independent grid of wells, is preliminarily calculated for the lower reservoir.
With known accumulated selections (Qi), the dynamics of reservoir pressure along the lower board is determined by the formula:
^form.init! ^foiminit (2)
2. Using the filtration coefficients "Ai" and "Bi", with a known gas flow rate qi and the reservoir
_i9
pressure value Pi, the bottom-hole pressure is determined Pci.
^1= Vl2^ - (¿1?! + SA2) (3)
3. Due to the insignificance of the distance from the lower layer to the packer and from the packer to the upper layer, to simplify further calculations, we accept
Pi = Pci U P3= P2.
Here the pressure P2 is determined by the formula:
f2 = e-Son /p^ - 1.377À/z2avformT2avf°rm.Q2cm1(e2Son - 1) (4)
pn" up.form.
4. Taking the pressure loss at the gas inlet from the upper reservoir into the tubing equal to 3 atm, the bottom-hole pressure P2 is determined by the formula:
= -éi+ i(M
®2 y VB2/
+
P
/orm.2"
P2 pc2
B2
(7)
Pc2 = P3. + 3
(5)
7. The total gas flow rate is equal to:
5. The change in reservoir pressure along the upper layer is controlled by the dependence:
Pform.2 = J(0g2)
(6)
(8)
6. At known values of reservoir and bottom - hole pressures, the flow rate of the well along the upper layer is determined by the formula:
8. The calculation of the wellhead pressure for the case of lifting a gas - liquid mixture of two layers on one tubing column is determined by the formula:
P =e-
Pw. e
P2
P3
1.377A™
22
wup.t
mix.tot
(e2
1) (9)
2
2
Where
S0 = 0.03415 PL :p = 0 + (1-0)-Pi
^av^av pg.w.
PgPavTh. ^ ^ 0
pg.w. -: 0 < ß = (Q Q ) ;
PatJav (Qg.w.Ql.)
0 = : 0 =£al£i. (10)
Vg.w. D ■ Vmix. fn -, • vlu/
Pn
^ = ^^ = -^ = 293°«-
P
air
(Z2 T2 )
0 = 1,377A(Z av (e2S - 1) ab
Pg, Pai>., Pi - the density of gas, air and liquid, Gl, Gg, - mass flow rate of liquid and gas, t/day;
respectively, kg/m3; Qm, Qi, Qg - the volume flow rate of the gas-liquid
Pg.w., Qg.w - accordingly, the density and flow rate mixture, liquid and gas, respectively, at Pai and Th,
of gas in the borehole under operating conditions, kg / thousand m3/ day. m3 and thousand m3 day;
Fact — - Forecacst
Fig. 1. Graphs of changes in reservoir pressure from accumulated gas extraction
p/z
500
Dependence of (he reduced average reservoir pressure on the accumulated gas production
150 100
P/z- 454,9 -0.4564082'Qr
Accumulated gas production, mill.ill
Fig. 2. Graph of the parameters of the DC of a gas condensate well when lifting the production of two layers in one column
The true volumetric gas content should be determined experimentally as the ratio of the true volume of gas Vu in the well to the volume of the hole
0 = However, due to the great difficulties of such measurements, it can be estimated by the consumable gas content p according to the above formula (10).
Since it is always 9 <p, the use of p instead of 9 leads to an underestimation of the downhole pressure the greater the difference between the amount of liquid in the well and the outflow of gas. The coefficient of hydraulic resistance I must be determined based on the results of well studies in various modes. Due to the absence of such studies, its value is assumed according to [4], for the pipe It = 0.025 and for the packer Ip = 0.0815.
All values (Zav Pg.w., Qg.w., P, etc.) depending on the Pav are calculated by the method of successive approximations.
The development of an oil and gas field is a capital-intensive technological process that requires a large construction program. Capital investments in the
development of an oil and gas field are determined by the main areas of work: drilling of producing wells, oil and gas field construction facilities, purchase of equipment not included in the construction estimates, other areas.
Capital investments in drilling production wells are determined for each option, which provides for a different number of wells, based on the volume of production drilling and the estimated cost of one meter of penetration, accepted according to the actual data of the exploration drilling department for one year for the field [5, 6].
The capital investments of gas field construction at the field (collection, transportation, gas treatment, transfer of wells to DC) are for each option, based on the actual volume of capital investments, fixed assets and specific capital investments per operating well.
Capital investments of oilfield construction at the field (collection, transportation, preparation of oil; collection, transportation of gas, transfer; wells to gas lift) are determined for each option that provides for a
personal number of wells, based on the actual volume of capital investments, fixed assets and specific capital investments for an operating well [7,8].
The procedure for calculating capital investments in drilling and field construction is determined in accordance with the regulations for drafting projects and technological schemes for the development of oil and gas and gas condensate fields. The calculation of operating costs for oil, gas and condensate production is carried out in accordance with the current calculation methodology, depreciation rates, approved rates of
The positive effect of using the technology of dual completion is expressed in reducing capital investments for the construction of wells for each of the operational facilities, in reducing operating costs and the development period of a multi-layer field, in increasing the production of hydrocarbons and the term of final
deductions for geological exploration. Standards of operating costs in accordance with the actual data of the calculation items of the cost of oil and gas production. Depreciation rates of fixed assets (except wells) are taken according to their average value, which has developed in the Gas Field Management and Oil and Gas Production Management for one year [9].
The accepted values of the enlarged standards for calculating capital investments and operating costs, together with the necessary additional data, are given in Table 1.
Table 1.
condensate recovery with cost-effective operation of wells. In addition, the use of this technology contributes to an increase in the utilization rate of downhole equipment and the reliability of the downhole installation [10].
Standards of capital investments and operating costs for Gas field management
Indicators Unit of measure
Capital investments:
Drilling of wells thousand man/m
Equipment not included in the construction estimates thousand man/well
Collection and transportation of oil thousand man/well
Gas collection and transportation thousand man/well
Complex automation thousand man/well
Industrial water supply thousand man/well
Power supply and communication thousand man/well
OGFM production service bases thousand man/well
The cost of road construction thousand man/well
Equipment of DC thousand man/well
Other facilities and costs thousand man/well
Total for fishing equipment: thousand man/well
Total: thousand man/well
Basic salary thousand man/well
Deductions for social insurance thousand man/well
Expenses for preparation and development thousand man/well
Maintenance and operational equipment costs thousand man/well
Shop expenses thousand man/well
Production costs thousand man/well
Operating costs
Other expenses thousand man/well
Total conditionally fixed depreciation costs: thousand man/well
Collection and transportation of oil and gas man/t
Technological preparation of oil man/t
Deductions for exploration work man/t
Electricity costs (with a mechanized method) man/t
Depreciation rate %
The price of natural gas man/1000m3
Oil price man/t
Total conditionally variable costs man/t
The system of dual completion from several productive horizons allows:
- The use of one well for the dual completion of several productive horizons in a multi-layer hydrocarbon deposit;
- Reduction of the number of production wells while ensuring planned oil and gas production indicators;
- Reduction of unit costs during well operation;
- Reducing the number of drilling wells, while ensuring the planned volumes of oil and gas production.
Calculations of the main forecast indicators for the production of oil, gas and condensate on the productive horizons of the Korpedje field are carried out in accordance with the requirements of the guidance documents for the design of the development of oil and oil and gas fields.
This article discusses three variants for the further development of the Korpedje oil field. The forecast of oil production by horizons and by location as a whole has been fulfilled for the period 20ii-2030.
According to the first variant, additional development of oil field is planned to be carried out by the existing fund of producing wells. Only on the horizon of NK-9 in block III, where a section with reserves of category Ci is allocated in the western part of the oil rim, on which there are currently no operating wells, it is recommended to drill one production well -№01.
In the second variant, it is planned to drill the eastern part of the oil deposit of the NK-7g horizon in block III.
In the eastern part of the block there is an unproductive well №52, through which a reservoir-limiting discharge 2 was carried out. However, the distance from well № 52 to productive wells No. 269,262 and 248 located to the west of it is quite large - 500 - 700m, as a result of which the position of discharge 2 cannot be considered reliably established -it can also pass significantly to the west of the position shown on the map. Therefore, this section of the deposit was not covered by drilling when drilling the main grid of wells.
It is recommended to drill 5 production wells in this zone - №02...06. The issuance of well points for construction must be carried out on the principle of "from the known to the unknown" - from west to east.
In the northern part of block, I of the NK-7g horizon in the western part of the oil rim, according to the data of testing and operation of well №53 (currently inactive), oil reserves of category G have been identified. Two priority production wells are recommended for laying here - №№ 07 and 08 [11].
Thus, according to the second variant, it is proposed to drill 8 new oil wells. The project wells recommended for drilling have been assigned conditional numbers starting with "O" (№№ 01, 02, etc.).
In the third variant of the further development of the oil field of the Korpedje field, exploration, transfer to category Ci and commissioning of the C2 oil reserves available at the field are envisaged.
According to long-term actual data of exploration of the lower red-colored field of Southwestern Turkmenistan, the coefficient of confirmed oil reserves when transferring them from category C2 to category Ci is on average 0.5.
The average efficiency of exploration for oil field in Southwestern Turkmenistan in recent years is determined by the increase in reserves of Ci. With this in mind, the commissioning of four productive exploration wells has been accepted. Drilling of five production wells is planned for the introduction of incremental reserves into development. Exploration drilling is scheduled to begin in 2015. Since the field is equipped for oil production, it is planned to put wells into operation from the same year. Taking into account the capabilities of drilling companies, drilling of incremental reserves ends in 2019.
The calculated parameters for oil reserves transferred from the C2 category are accepted at the level of the average for the field [12].
The indicators of exploitation of the developed field with reserves of category Ci according to the third variant are the same as for the first variant.
The indicators of production drilling for the variants of additional development of oil field are shown in the table 2 below.
Table 2.
Indicators of production drilling by variants for further development of oil fields
Indicators Commissioning of new wells
Average depth of new wells, m
Metric area of production drilling, thousand meters
I variant 1
4200 4,2
II variant 8
3675 29,4
III variant 10
4033
24,2
The metric area of exploration drilling according to the III variant is i6 thousand meters. Four wells with an average depth of 4000m are planned for drilling.
The calculations take into account the actual dynamics of changes in the main indicators of the development of operational facilities over the past period and its projected change for the future and the commissioning of new production wells recommended for drilling. When calculating oil production by
development facilities (by horizons), the transfer of wells to the overlying horizons is also taken into account. The initial flow rates of the wells put into operation are estimated taking into account the depletion of block reserves and the current state of the working wells [i3, i4].
The ratio of liquid and oil flow rates indicates the presence of emulsions of increased viscosity (taking
into account the fact that the extracted oil is highly paraffinic).
There are high (1,6-2,5 MPa) buffer pressures at the wells, which with the installed regime fittings on the buffers of wells with a diameter of 16-25 mm, which indicates high hydraulic resistances during the movement of the gas-liquid mixture in the collection system of high-paraffin oil, including the pressure drop in the regime fittings of wells with a large gas factor).
We note that the magnitude of the total gas factor and, accordingly, the required specific flow rate of the working agent supplied to the well depends on a set of factors, including, in particular, the depth of gas input into the tubing column chosen during the design of the elevator (immersion under the dynamic level).
The choice of the gas input system into the elevator (starting valves, working valves, starting holes) made during the design of gas lift wells can lead to significant deviations in the technological parameters of the working well from the option of single-point gas input under the lift shoe, which is usually taken as the basis of standard calculations [16].
Such a significant discrepancy is observed for the wells of the Korpedje field, where starting holes ("Punchers") are used. At the same time, it is difficult to calculate the required pressure of the working agent.
Taking into account the use of the working agent of the gas lift up to 8,0 MPa at average depths of gas input into the elevator and the need to deepen the points of gas input in the future during the development of field, the pressure of the working agent should be selected in the range of 9,0-10,0 MPa.
Taking into account the presence of a compression line for associated gas from an inlet pressure of 0,3 MPa to 7,5 MPa, which has a throughput capacity of 1 billion m3, it should be considered expedient to continue using a compressor-free gas lift scheme with utilization (compression on the CS) of associated gas, which is a mixture of petroleum gas and a working agent. At the same time, it is proposed to compress natural gas extracted from gas condensate wells with a wellhead pressure of 4,5-5,0 MPa to the required pressure of 9,010,0 MPa using booster compressor stations of block type, for example, BCS 28NM/1 with a capacity of 1,1 MW, with a capacity of 500 m /day. The experience of operating these compressor stations is available at the Goturdepe and Barsagelmez fields [17].
The amount of gas supplied for the gas lift is determined based on the average specific consumption of the working agent, determined by the formula:
Rwork = Rtot — Gf
where is Rtot - the total specific flow rate required for lifting the liquid by gas lift (Rtot = 500m3 /m3,);
Gf - is a reservoir (borehole) gas factor.
Three variants for the development of gas field of the Korpedje field are considered.
The first variant is basic. Development is provided by the existing well fund.
In the second variant, drilling of 20 new producing gas wells with a total area of 69 thousand meters is
recommended for the horizons NK-9, NK-8, NK-7d, NK-7g and NK-76 in 2012-2018.
In the third variant, it is recommended to refrain from drilling five new wells on the horizons of NK-76 and NK-7g by opening these horizons with the use of DC in wells projected on the underlying horizons. Thus, according to the third variant, 15 new production gas wells with a total area of 53 thousand meters are recommended for drilling. The commissioning of wells from drilling has been planned since 2012 - 2 wells: in 2013 - 3 wells; in 2014 - 2 wells, in 2015 - 3 wells, in 2016 - 2 wells, in 2017 - 2 wells and in 2018 - 1 well.
In all variants for wells of the existing fund, it is planned, after working off the exploited horizon, the production of well returns to the overlying horizons. Gas field, the development of which involves the use of DC, for each pair of horizons are located in tectonic blocks of the same name and have a similar relationship with the legal area, and, consequently, similar drainage regimes. This is a good condition for ensuring approximately the same rate of fall of reservoir and wellhead pressures over a long period. It is also recommended to continue the operation of wells with DC equipment and wells with downhole gas lift currently operating.
The determination of the parameters of the operation of gas wells and the forecast of the indicators of the development of gas condensate field are carried out on the basis of reserves of gas condensate horizons and areas for which the presence of oil rims has not been established. When determining the initial recoverable gas reserves, the expected final gas recovery coefficient of 0,85 was adopted.
Based on the analysis of field data using the available actual data on reservoir pressure measurements for horizons, dependences of reservoir pressure changes on accumulated gas extraction were constructed in a dimensionless form. When it was taken into account that for the gas condensate field of Korpedje, as well as other field in the region, during the development process, an increasing share of participation in the drainage regime of the pressure of marginal and plantar waters is manifested over time.
Each of the horizons under consideration is an independent operational object with its own design grid of wells. Therefore, the use of DC technology will significantly reduce the number of wells for drilling, and, consequently, the material and technical costs associated with drilling the field as a whole.
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Deryaev Annaguly Rejepovich
Candidate of Technical Sciences, Senior Researcher, Scientific Research Institute of Natural Gas of the State Concern „ Turkmengas ",
Ashgabat, Turkmenistan
RECOMMENDATIONS FOR THE USE OF HYDROCARBON-BASED DRILLING MUD
Annotation: The paper considers the program of replacement of drilling mud for interval drilling for the technical and operational column of the directional rectilinear interval of an exploration well. The procedure for replacing the ALKAR-3M drilling mud with a "Versadril" type hydrocarbon base solution and the recipe for its preparation are described in detail. Recommendations are given for the preparation of hydrocarbon-based drilling mud for the 295.3 mm and 2i5.9 mm sections of the open trunk of an inclined directional exploration well.
This work can be used to conduct drilling operations in deep wells in fields with difficult mining and geological conditions, in order to successfully achieve the design depth and eliminate complications associated with oil seal formation, absorption and accidents with the seizure of drilling tools during drilling.
Key words: solid phase, fluid, rheological properties, sand trap, water release, absorption, pressure regression, coiiector.
Let's consider the preparatory work on the preparation of a hydrocarbon-based drilling fluid for the exploration well №204 on the Northern Goturdepe field from a depth of 3000-4662 meters. The volume of the solution is directly proportional to the volume of the solid phase in the solution system. The increase in the solid phase content in the solution should be maintained at a minimum level in order to reduce the cost of drilling fluid and drilling in general. Removal of the solid phase from the solution can be achieved by using a double centrifuge system operating at low and high
speeds to remove the fine solid phase and return the fluid to the system and regenerate the barite.
Diesel fuel L-0,2-62 is necessary for drilling fluid sealing due to the fact that the hydrotreated fuel does not provide the necessary parameters of the solution and requires a large consumption of chemical reagents.
When mixing, we recommend installing a shear agitator on the drilling rig (a hydraulic mixer with a high shear effect) to significantly improve the mixing of a hydrocarbon-based solution, which will significantly reduce the use of orgophilic clay at the initial stage of mixing the solution, which in turn leads
