ROAD MAPS OF TECHNOLOGY “SMART HORIZONTAL DRILLING”

The main task of the 3D seismic survey complex on scattered waves and the 4D microseismic method, which form the basis of “Smart Horizontal Drilling» (SHD) technology, is to reduce drilling costs, as well as increase the flow rate and safety of drilling. The solution of this task is ensured by a series of geological and technical measures at all stages of drilling: from the choice of the location of the well and the direction of its horizontal section to the stage of operation of the well.  The road map for SHD includes the following stages:

  1. Specialized data processing of 3D / 2D CDP for the prospective drilling site by the CSPD method
  2. Analysis of cubes (or sections) of CSPD diffractors and CSPD reflectors in order to identify zones of abnormally high reservoir pressures, untreated faults and open fracture zones
  3. Selection of the location of the well and the optimal direction of the horizontal section of drilling
  4. Deployment of the surface microseismic antenna and conducting passive background microseismic monitoring to identify active geological faults in the area of ​​drilling the well and directions of maximum stresses in the medium
  5. Drilling a well with microseismic support of the drilling process
  6. Carrying out multi-stage hydraulic fracturing (MSHF) and its microseismic monitoring
  7. Port productivity evaluation

Stage #1.  Specialized data processing of 3D / 2D CDP for the prospective drilling site by the CSPD method

The input data for special processing using “CSPD-PSTM 2D / 3D” software are pre-prepared seismograms (after standard processing) 3D / 2D CDP in SEG-Y format. The output data of the special processing are cubes (cuts for 2D) of CSPD diffractors and CSPD reflectors in the SEG-Y format (Fig. 1)

Figure 1: Separation of reflected and scattered waves by the CSPD method

Of great practical importance are the minimum sizes of the 3D MOGT data area required for the use of SHD technology for a single well. Parameters determining the size of this area are: (a) the depth of the target horizon, (b) the value of the standard horizontal well drill and (c) the CDP fold, which provides the required quality of seismic data processing results for the reliable application of the proposed technology. Assuming that the depth of the target horizon does not exceed 3000 m, the standard horizontal well drill is no more than 1000 m horizontally, the fold is not higher than 240 in the 2×2 km section (receiver step 50 m, source step 50 m, step between receiving lines 150 m, step between lines of explosion 300m), we find that the minimum size of the site that meets the necessary requirements is about 100 square meters. km (Fig. 2). Not an optimal but acceptable fold of 100, in this area also provides a standard recording system with a pitch between receiving lines of 300 m (Fig. 3).

Figure 2: The fold of the observation scheme with the distance between the lines of the explosion is 300 m, the reception is 150 m. The step along the receiver line  and source line is 50 m. The total fold of the section is 2×2 km – 240

Figure  3: The fold of the observation scheme with the distance between the lines of the explosion is 300 m, the reception is 300 m. The step along the receiver line  and source line is 50 m. The total fold of the section is 2×2 km – 100

Stage #2. Analysis of cubes (or sections) of CSPD diffractors and CSPD reflectors in order to identify zones of abnormally high reservoir pressures, untreated faults and open fracture zones

At this stage, interpretation of the results of special processing is carried out, permeable and impermeable (fluid and gas-saturated) faults are distinguished. Figure 4 shows the results of processing CDP materials at the Sungliao Basin (China) in section, and in Fig. 5 – in terms of two productive horizons: upper T2 and lower T3.

Figure 4: Break-block model of the field. Sungliao Basin, China

Figure 5: Maps on horizon T2 with permeable faults and horizon T3 with impermeable faults. Sunlao Pool (China)

At the same stage maps of amplitudes of scattered waves are constructed. High amplitudes of scattered waves are associated with both zones of anomalous reservoir pressures of the overproductive horizons, and with zones of open fracturing of productive horizons. The first ensure the identification of areas that are the safest for vertical drilling. The latter are used to design the direction of the horizontal trunk during drilling and the optimal implementation of the MSHF.

Testing of the proposed method was carried out on seismic materials of the  3D CDP Kovyktinsky oilfield.  Figure 6 shows CSPD-diffractors in the productive horizon. Figures 7 show an example of the detection of zones of abnormally high reservoir pressures (brine manifestations) in the interval of the Bilchir horizon using the CSPD method. Figure 8 presents similar information on the underlying Christoforovsky and Balytyn horizons. Figure 9 shows the locations of the zones of possible geological complications during the drilling of all three Cambrian intervals of the geological section.

Figure 6. CSPD-diffractors in the productive horizon

Figure 7. Distribution of total amplitudes of scattered waves in the interval of the Bilchir horizon (isochronous surface)

Figure 8 Distribution of total amplitudes of scattered waves in the interval of the Christophor and Balytyn horizons (isochronous surface)

-fracture zones in bilchirskom horizon

-fracture zones in hristofor and balyhtinsk horizons

-fracture e zones in parfen horizonr

Figure 9: Scheme of the location of zones of possible geological complications during the drilling of the Cambrian geological section by wells (overproductive deposits)

A three-dimensional image of the zones of open fracturing is shown in Fig. 10.

Figure 10: Open fracturing zones based on the results of special processing of 3D CDP data using the CSPD method

Below are the fragments of vertical sections of cubes of reflected and scattered waves at one of the deposits of Western Siberia (Fig. 11).

Figure 11: Time section of CSPD reflectors (on the left) and CSPD diffractors (on the right) of the section of the Bazhenov suite

Stage #3. Selection of the location of the well and the optimal direction of the horizontal section of drilling

At this stage, the spatial arrangement of the fracturing zones is analyzed, zones and directions are clearly marked with a pronounced compactness and elongation of the structures (Fig. 12). Given the experimentally established high correlation between the total fracture index – DD (Diffracivity Density) and the TG oil index for horizontal well sections (see Fig. 13), which reaches 92%, it is proposed to automate the process of selecting the direction of horizontal drilling. According to the cube of CSPD diffractors on a computer, the DD index is calculated for different horizontal directions from the entry point of the well to the production horizon (Fig. 14).

Optimal, in terms of potential productivity, is the direction with the maximum calculated index DD (yellow direction in Figure 14). Here, the perforation points (ports) for the MSHF are determined, which should be in zones of maximum fracturing (red-yellow zones).

Figure 12: An example of the design of a horizontal section along an explicitly extended fracture structure in the rocks of the Bazhenov suite

Figure 13: Correlation of the CSPD dispersion index with reservoir productivity from data in horizontal wells

Figure 14: Results of calculations of the total fracture index along 8 horizontal directions. The length of the horizontal section of the well is 1 km

Futher, from the point of view of the safety of the MSHF, it is important to take into account the directions of the horizontal components of the maximum and minimum stresses in the medium. If the trunk of a horizontal section of a well designed to pass through zones with a maximum of natural fracturing (DD index), will not be orthogonal to the directions of maximum stresses in the medium, as necessary, i.e. will pass at an acute angle to these stresses (Fig. 15), possible emergency situations during the MSHF. To rule out such cases, it is necessary to change the direction of drilling, possibly reducing the coverage of natural fracturing zones, so that the trunk is orthogonal to the direction of the maximum stresses of the medium (Fig. 16).

Figure 15: Example of designing a horizontal section of a wellbore for an MSHF with maximum coverage of natural fracturing zones, but not orthogonal directions of the main stresses of the medium

Figure 16: An example of the optimal design of a horizontal section of a wellbore for conducting an MHRP with an orthogonal direction of the main axes of the stresses of the medium

Stage #4. Deployment of the surface microseismic antenna and conducting passive background microseismic monitoring to identify active geological faults in the area of ​​drilling the well and directions of maximum stresses in the medium

In order to identify active geological faults in the area of drilling the well, identify the directions of the main stresses, and also control the drilling of the MGRS itself, and subsequently evaluate the productivity of the ports, a surface microseismic antenna is deployed from 400 broadband (0.1-100 Hz) seismic recorders on an area of 1.0 square km. (Fig.17). With a sampling step of 0.5 ms, the monitoring depth will be from 700 to 5000 meters.

A month before the drilling commences for at least two weeks, background passive microseismic monitoring of the environment can be carried out. The purpose of this monitoring is to identify active faults in the area of ​​the forthcoming drilling. Figure 18 shows the results of such monitoring of well#1 at the Galianovskoye field in Western Siberia within one month. The target horizon is the Bazhenov suite. Events related to passive monitoring are highlighted in green. These events clearly reveal the presence of an active deep vertical fault up to depths of 3.5 km, extending in the north-west direction from the bush of wells.

To identify the directions of the main stresses, a mini-hydraulic fracturing is performed in the well located in the sensitivity zone of the microseismic antenna.

Fig. 17 Microseismic acquisition data system

Figure 18:  Results of passive microseismic monitoring of wells. Green color – the results of additional passive monitoring

Stage #5. Drilling a well with microseismic support of the drilling process

The pre-installed registration system (Figure 19) of microseismic events allows additional monitoring of all stages of the drilling process. So, in Figure 20, frequency-time information from one seismic sensor is presented. It turns out that even such information is sufficient for a complete technological analysis of the drilling process. In addition, the noise of the chisel can restore the trajectory of drilling in space. Figure 21 shows the result of processing the data of microseismic monitoring of the drilling of an inclined well in the Potanai field (trajectory of a drill bit).

Figure 19:  Microseismic monitoring of the drilling process

Figure 20: Changing the frequency spectrum of the seismic sensor while drilling

Figure 21: The location of the drill from the results of microseismic monitoring

Stage #6. Carrying out multi-stage hydraulic fracturing  and its microseismic monitoring

At this stage of “Smart Horizontal Drilling” technology with the help of microseismic monitoring of the MSHF, the following tasks are solved:

  • Determination of the length and azimuth of the fracture zone
  • Visualization of the development of the zone of fracturing in time
  • Determination of the energy parameters of microseismic events and the process of fluid injection
  • Visualization of the area of microseismic activity
  • Construction of energy density maps
  • Analysis of the stages of the MSHF based on the calculation of energy parameters

Figures 22-23 show the visualization of the results of 4D microseismic monitoring of the MSHF. Figure 22 shows the results of microseismic monitoring of the 1st stage of the horizontal section of the MSHF well, which included such operations as Replacement, Mini-MSHF and basic fracturing. On the basis of the selected microseismic events, the length, the azimuth of the technogenic fracturing are determined, and the events are linked to the MSHF time diagram. In addition to the coordinates and timing of the occurrence of the microseismic event, the energy parameters (absolute energy, magnitude, deformation energy of isotropic compression / expansion, the energy of maximum separation / contraction / shear stresses, etc.) are determined. Energy parameters of microseismic events are calculated on the basis of the seismic moment tensor, which can be represented in the main axes as three perpendicular vectors. Calculation of the energy density of microseismic events makes it possible to construct a contour of the region of microseismic activity (isosurface of density). On the cutoff of this region, one can observe the density of microseismic energy (Fig. 22).

Figure 22: Results of microseismic monitoring of the 1st stage of the MSHF

Figure 23: Results of microseismic monitoring of the MSHF

Stage #7. Port productivity evaluation

After performing the MSHF, a surface antenna can be used to evaluate the performance of ports. Figure 24 shows the results of a two-week observation of microseismic emission of the horizontal section of the well. It can be seen that microseismic activity is associated only with the last three ports No. 4-6 (the numbering of the ports goes from right to left, the corresponding intervals of the wellbore are highlighted in colors), which is confirmed by well measurements (Figure 25).

The map of the events registered during and after the MSHF is presented in Figure 26. Figures 27-29 show the results of microseismic monitoring in conjunction with data on natural fracture zones obtained from the CSPD diffractor cube.

Figure: 24: Results of passive microseismic monitoring after MSHF in the well

Figure: 25: Port performance evaluation 

Figure: 26: Map of monitoring results of the MSHF horizontal well and subsequent passive monitoring. Blue lines are faults. The black line is the projection of the well trajectory. The color shows the structural map

Figure: 27: Vertical section of a cube of CSPD diffractors with superimposed monitoring results of an MHRP horizontal well. Red means increased natural fracture

Figure: 28: Horizontal section of the cube of CSPD diffractors with superimposed results of microseismic monitoring up to the MSHF of the well (a) and after the MSHF (b)

Figure: 29: Horizontal section of the cube of CSPD diffractors with superimposed monitoring results of the horizontal well MSHF and the optimal well trajectory for the MSHF