Page 386 - Fundamentals of Gas Shale Reservoirs

366 GAS SHALE CHALLENGES OVER THE ASSET LIFE CYCLE

Reservoir characterization
Seismic 2D, 3D- Well spacing
Attribute analysis GIP, OIP, economics, field development
Special processing identify sweet spots, artificial lift
Well info, tops, casing point well targeting
facility
project economics
Geology structure, Lithofacies
zonation
Reservoir modeling
Petrophysics
Toc, Ro, porosity,
hydrocarbon Static reservoir Dynamic Geomechanical
saturation model reservoir model effects
rock mechanics predict performance
density, acoustic,
image, cores
mineralogy Geomechanical Proppant
model
placement

Frac optimization
Microseismic completion design,
Frac model Predict
well performance single well
economics
Fracturing

FIGURE 17.3 Shale engineering life cycle workflow (Source: Baker Hughes).

17.4.5 Generate a Field Development four vertical wells (number can be higher depending on the
Plan—Current Practice particular shale play). Usually, a full plan also includes com-
pletion and fracturing designs. It has been determined that a
Most US operators have utilized the classic approach for large number of wells are required to develop either a shale
field development plans (FDP), having been successful in gas or shale oil play. Typical shale gas well spacing in the
generating FDPs in the past for conventional reservoirs. United States is approximately 116 acres (Kuuskraa et al.
However, shale gas has introduced uncertainty in the tradi- (EIA), 2011); however, the continuous shale formations
tional approach. The US operators have certainly realized extend over large geographical areas. Figure 17.4 shows the
that there are other considerations for development with number of existing wells in the six major US shale gas plays
horizontal wells in shale, especially including lease line and the total number of wells required to develop the techni-
considerations.
cally recoverable resources (TRR) from EUR per well
(Kuuskraa et al. (EIA), 2011) for each play using the typical
17.4.6 Generate a Field Development number of 200–300 wells required to recover 1 tcf of gas.
Plan—Recommended Practices Most plays have not yet even approached the required
number of wells.
Field development plans should include well type, placement,
attitude, direction (azimuth), and spacing (drainage area
considerations). For shales, wells should be drilled in the 17.4.7 Validate Economics of the Play or Pilot Project
direction of minimum principal stress, which maximizes
access to existing natural fractures when transverse‐trending Now, with all of the data collected from the drilling and anal-
hydraulic fractures intersect the natural fractures near the ysis of the appraisal wells, and with an understanding of the
wellbore. Therefore, it is important to understand the stress unique aspects of these unconventional reservoirs and char-
regime in the field. Most development wells in the United acterization data for the particular play, operators can
States are horizontals, this is partly due to the “relatively complete the final step of the appraisal phase—validating
thin” shale formations ranging from 20 to 600 ft thick. the economics of the play. Operators can then evaluate prior
Horizontal wells also maximize reservoir contact resulting to taking the decision whether or not to proceed with play
in a cost advantage over drilling a larger number of vertical development. This has been the typical sequence of events in
wells. The literature says that one horizontal well can replace the United States.