Fracture Communication in Carbonate Reservoirs Based on G&G and Production Data. E.N. Dulaeva (TatNIPIneft Institute)

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1 Fracture Communication in Carbonate Reservoirs Based on G&G and Production Data. E.N. Dulaeva (TatNIPIneft Institute) In conditions of current exploration maturity, when attention of the industry is shifting from depleted porous reservoirs to unconventional reservoirs with permeability and porosity determined by fractures, methods that allow predicting areas with high flow properties acquire increasing interest and rapid development. In different years, experts of different directions were studying the issues of fracturing of the Bashkirian and the Serpukhovian sediments and potential for increased flow rates from fractured reservoirs. Different survey methods were used to identify fractured areas, including 3D seismic survey, aerial photography, side-view seismic location (SVSL), offset vertical profiling methods, tracer investigations, core macro description, etc. Interestingly, results of different survey methods gave different directions of fracturing zones axes. To determine actual direction of axes of fracturing zones in Deposits Nos in the Romashkinskoye field, the authors attempt an alternative analysis based on the well production data. Deposits Nos in the Romashkinskoye field confined to the Bashkirian and the Serpukhovian sediments of the Kuakbashsky bar of the South-Tatar uplift are assigned to nonconventional type of the reservoir. The Serpukhovinan carbonate sediments initially characterized by high primary porosity (ballstone, bioclastic detritic limestones) were subject to intensive processes of desalinization in the epigenesis phase. The subsequent processes of sulphatisation and calcitation locally decreased high secondary porosity. At the beginning of the Bashkirian stage, unstable tectonic mode and frequent reverse of oscillating motions caused washout of carbonate sediments. Paleogeografic instability led to formation of different sediments from clay to dolomite and bioclastic limestones with low primary and quite high secondary porosity, which were deposited on the uplifts crests and flanks and also in depressions. The unstable tectonic mode caused fracturing. The Bashkirian and the Serpukhovian sediments are connected by the system of vertical fractures. This determines the massive type of the reservoir and the shared oil-water contact (OWC). Detection of orientation of flow channels in fracturing zones will make it possible to determine the highest-quality intervals, thus, increasing the efficiency of reservoir pressure maintenance system and optimizing the reservoir development. Location of horizontal wells in carbonate sediments shall be selected with account of the direction of fracture axis. 1

2 Based on specific productivity and mud loss data, the most permeable zones of Deposits Nos have been localized and directions of their strike have been defined: northeast (southwest) and northwest (southeast). Vector lines corresponding to directions of axes of fracturing zones have been drawn based on the production data and mud loss data. Based on the analysis of 3D common depth point (CDP) seismic survey shot in 2002, a seismic data volume for Deposits Nos of the Romashkinskoye field Kuakbashsky area was obtained. Ant tracking for analysis of the azimuthal orientation of fracturing was originally made in two directions, the north-eastern coinciding with the direction of the regional tectonic bending zones according to the results of aerial photography, and north-western coinciding with the direction of the decompression zones according to results of side-view seismic location and offset vertical profiling. The development history of Altunino-Shunaksky deflection and the Kuakbashsky bar suggest that the northeast direction is the dominant direction of signatures in seismic recording, which are recorded from the Middle to crystalline basement and which are associated with tectonic faults identified by 3D seismic survey (2004). Results of seismic survey partially agree with the conclusions of authors. To prepare data for sidetracking six deep wells, offset vertical seismic profiling was performed. Differentiation of the area of interest in terms of fracturing extent was carried out based on the results of the analysis of the waves energy reflected from the Bashkirian surface. Areas with residual values of reflected energy were associated with high-fracturing zones (loose rocks), while areas with high energy were regarded as dense rock. The well data analysis shows that dominant fracturing orientation is southeastern, which intersects the northeastern fracturing direction. However this survey method only provides characteristics of the near-wellbore region ( m), while information about regional fracturing remains uncertain. Based on different directions of fracturing zones that have been obtained, we built two maps with different orientation of fracturing zones. Then, we analyzed geologic and production well data taking into account decompression zones according to the results of 3D seismic survey. We found out that improved permeability and porosity are characteristic both of the identified decompression zones and dense zones. Therefore, based on 3D seismic survey shot in 2004, express-analysis of fracturing was performed taking into account distribution of zones of disastrous lost circulation, well productivity and watercut. Using different parameters, forecast of fracturing zones was made within the Bashkirian, Vereiskian formation. The information is presented on maps of geophysical fields at various depths of the geological section. 2

3 Comparison of production data of the Bashkirian sediments (Deposit No. 302) with seismic survey interpretation data, tracer investigations results, and core analysis results led to the following conclusions (Fig. 1): Tracer investigations in the injection wells Nos and showed that maximum velocity of fluid flow is observed in the southwest and southeast directions. Injection wells with the highest presence of tracer fluid are located in the decompression zone according to seismic survey interpretation data. Based on the core analysis data, majority of wells (85%) with fractures are in the decompression zones. The remaining 15 per cent of wells with signs of secondary porosity are outside decompression zones mapped by seismic survey. It can be concluded that there is no perfect match between seismic survey and core analysis. Analyzing distribution of decompression zones identified by different methods, that is, seismic survey, information on lost circulation, and watercut data, it is valid to say that decompression zones are characterized by initial water cut of more than 20% and a very short water-free production period (3 months on the average). Disastrous lost circulation was also recorded in wells located in decompression zones detected by seismic survey. As for comparison of production data with G&G data for the Serpukhovian sediments (Deposit No. 303), the conclusions are as follows (Fig. 1): The comparative analysis of the Serpukhovian sediments was carried out by all above methods. Majority of wells with initial water cut of more than 20%, high productivity, and disastrous lost circulation are also associated with the fracturing zones according to seismic survey. The offset vertical profiling, tracer investigations, recovery of the oriented and fracturing core were carried out on the area enveloped by seismic survey. However not all abovementioned wells are located in fracturing zones detected by seismic survey. Some wells are situated in dense areas (Fig. 2). Thus, the fracturing zones detected by seismic survey and by production data coincide to a greater degree. To determine the most permeable intervals in a wellbore, fluid movement/injectivity profiles are analyzed. Among known methods are Remote Downhole Flowmeter (RDF), Downhole Thermoconductive Flowmeter (DTF), Flowmeter, borehole temperature indication, thermal log, water-cut log and profile logging. Out of 127 analyzed wells, 53 wells (41.7 %) lack flowmeter surveys; surveys carried out in 45 wells (34.5 %) are incomplete for one reason or another. Possible causes: nonpassage of geophysical tools in a wellbore down to target depth; clogging of instrumentation sensors in the process of recording or tripping; 3

4 Fig. 1. Comparison of fracturing model of sediments of Deposits Nos based on results of 3D CDP seismic survey and rpoduction data. 4

5 Fig. 2. Comparison of fracturing model of sediments of Deposits No. 303 based on results of 3D CDP seismic survey and rpoduction data. damage of production casing and behind-the-casing flows distorting results of measurements; poor representativeness of results etc.. Ten wells (7.9 %) were investigated only partially and don t give a full picture of formation. More or less detailed and comprehensive information allowing to draw some conclusions about reservoir performance have been obtained only in 19 out of 127 wells (15 %). Horizontal laterals of these 19 wells are oriented in the following directions: 5 wells are in northeast southwest direction, 5 wells are in northwest south-east direction, and 5 wells are in submeridianal direction, and 4 wells are in the sub-lateral direction. 5

6 By results of profile logging, the producing interval makes from 0.3 % to 99 % of the entire length of the open completion, irrespective of the direction of the horizontal lateral. When more than 40 % of the borehole is producing (5 out of 19 wells) we can make a conclusion about relative homogeneity of the drilled formation. When less than 40 % is producing (14 out of 19 wells) it suggests considerable lateral heterogeneity of the reservoir. In this case a small interlayer is more permeable in comparison with the other part of the penetrated productive zone and the drawdown conditions prevent inflow from the adjacent interlayers. In wells with the share of producing length less than 40 % the most permeable intervals are located: in the "toe" of the horizontal well, that is, the inclined section close to the reservoir top; in the middle part of the horizontal latera;l permeable intervals are distributed all over the length of the horizontal lateral. All wells drilled in the northeast south-west direction, drain just a very insignificant part of the penetrated section ( %), while wells drilled in other directions may produce from low-thickness intervals and thick layers (Well No H) (Table 1). Analysis of the wells performance profile showed the following: initial oil and water production rates differ insignificantly, irrespective of the well direction; average initial water cut of the wells drilled in northeast southwest direction is higher (22 %), than that of wells in other directions (from 5.6 % to 13.5 %); the shortest water-free period (3 months on the average) is in the wells drilled in the northeast southwest direction, the longest water-free period (17 months on the average) is in wells drilled in the northwest southeast direction; the highest average current water cut (94 %) and the lowest average daily oil production rate (0.48 t /d) are in wells drilled in the northeast southwest direction; the highest producing length (42.8 % on the average) and the lowest current water cut (78.5 % on the average) are in wells drilled in the submeridional direction. Technical and economic data model for a choice of the most effective horizontal borehole s direction based on G&G and production data. Evaluation of production data was carrying out with use of technology applied in OAO Tatneft: - annual well production rate decrease is 5 percent; - annual water cut production growth is 2-3 percent. Basic data for carrying out of economic appraisal are provided in table 2. 6

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8 The main basic data Table 2 Characteristics Datum Note Cost price Urals oil price, $US/bbl year preview Dollar exchange, RUB 33,4 Disposal price net of VAT, EP, and selling costs, RUB/ton 9939 Taxes Royalty, RUB/ton 5426 Profit tax, RUB/ton 20 Insurance premiums, percent 30 Wealth tax, percent 2,2 Capital investments Drilling cost, ths RUB/m, including - vertical wells 24,6 - horizontal wells 33,9 - multibranch wells 31,1 - slim hole wells 20,3 - prospecting wells 0,0 Side-tracking, MM RUB/well 24,6 Horisontal side-tracking, MM RUB/well 29,2 Manufacturing costs Semi-variable costs, RUB/ton fluid 64 Fixed costs, ths. RUB/ production well year 1676 Fixed costs, ths. RUB/ injection well year 1200 Injection costs, RUB/ m³ 22,0 Production well shifting costs, ths. RUB/well 1848 Well re-completion costs, ths. RUB/well 2254 Well s retirement costs, ths. RUB/well 2316 Other Residual cost on , MM RUB Discount rate, unit fraction 0,1 Salary PPP, ths. RUB 33,1 Specific number of PPP for one producnion well 0,6 Production data are provided in table 3. The main technical and economic data for a choice of the most effective horizontal borehole s direction are provided in table 4. Expected economic effect is defined by normative documents [3-5]. 8

9 Direction of horisontal wells NW-SE NE-SW Submeridional Sublateral Year Main production data Water production, ths. Tones Oil producnion, ths. Tones Water cut, percent , ,10 12, , ,50 16, , ,77 21, , ,58 25, , ,60 29, , ,52 32, , ,05 36, , ,89 39, , ,30 35, , ,89 38, , ,24 41, , ,03 44, , ,93 47, , ,63 50, , ,85 52, , ,31 55, , ,50 27, , ,98 31, , ,48 34, , ,65 38, , ,17 41, , ,71 44, , ,98 47, , ,68 49, , ,10 15, , ,20 19, , ,54 24, , ,76 27, , ,52 31, , ,49 35, , ,37 38, , ,85 41,60 Table 3 9

10 Main technical and economic data Table 4 Direction of horisontal wells NW-SE Direction of horisontal wells NE-SW Direction of horisontal wells Submeridional Direction of horisontal wells Sublateral Characteristics Oil production, ths. tones 19 Revenues, MM RUB 184 Capital investments, MM RUB 29 Operating costs, MM RUB 151 Net present value, MM RUB 12 Cost's productivity index, unit fraction 1,09 Investment's productivity index, unit fraction 1,40 Payoff period, years 4,61 Characteristics Oil production, ths. tones 18 Revenues, MM RUB 181 Capital investments, MM RUB 29 Operating costs, MM RUB 150 Net present value, MM RUB 10 Cost's productivity index, unit fraction 1,08 Investment's productivity index, unit fraction 1,36 Payoff period, years 4,81 Characteristics Data Oil production, ths. tones 19 Revenues, MM RUB 188 Capital investments, MM RUB 29 Operating costs, MM RUB 153 Net present value, MM RUB 12 Cost's productivity index, unit fraction 1,10 Investment's productivity index, unit fraction 1,43 Payoff period, years 4,49 Characteristics Data Data Data Oil production, ths. tones 20 Revenues, MM RUB 194 Capital investments, MM RUB 29 Operating costs, MM RUB 156 Net present value, MM RUB 14 Cost's productivity index, unit fraction 1,11 Investment's productivity index, unit fraction 1,49 Payoff period, years 4,23 10

11 Table 4 showed that sublateral direction is the most effective direction for horizontal well s drilling. The Net Present Value (NPV) will make 14 MM RUB, and payoff period is 4.23 year. Submeridional and northwest southeast directions are also effective. The least effective direction is the northeast southwest direction for horizontal well s drilling. List of references: 1) Amirov A.N., Ishuyev T.N. Vertical seismic profiling method of deep wells and development of a technique and equipment for studying borehole environment. Report of production seismic party No. 23/89, ) Doronkin A.K. Preparation of data necessary for drilling of horizontal wells on Kuakbashskiy bar (deposits Nos ). Report of seismic logging party No. 24/2002. Bugulma, pages. 3) Methodical recommendations for complex assessment of efficiency directed on precipitation of scientific and technical progress in the oil-producing industry. RD 39-01/ M.: MNP, pages. 4) Methodical recommendations for assessment of efficiency of investment projects: (Second edition) / Ministry of economy of Russian Federation, Financial Min. Russian Federation, group of companies of construction, architecture., and also residential policy. - M.: Economy, pages. 5) Rules of order design technological documents for development oil and gas-oil fields. RD M.: Ministry of Industry and Energy of Russian Federation, pages. 11