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The modelling results from numerical simulations of the Early Cretaceous, Mannville coal measures with anisotropic permeability provide insights into development strategies not readily visualized or otherwise intuitive. The complex relationships between water and gas production, the contribution from multiple coal seams as well as from organic rich shales, and the impact of well interference combined with anisotropic fracture permeability are investigated through a series of numerical simulations of four well-pads (on the corners of a square mile of land with decreasing well spacing from 1, 3, to 4 laterals per pad). After 25 years of production, the two pads with optimally-oriented laterals with respect to the fracture permeability anisotropy produce 61% of the recovered gas for the 1 lateral/pad model, 52% for the 3 laterals/pad model, and 50% for the 4 laterals/pad model. Downspacing has a greater impact on increasing the gas production from pads with the poorly-oriented main laterals than from the pads with the optimally-oriented main laterals. The cumulative gas production at the end of the 25 year history is 4.2% higher for an optimally-oriented pad (pad1) and 1.1× higher for a poorly-oriented pad (pad3) for a model with 4 laterals/pad than 3 laterals/pad and an optimally-oriented pad is 1.1% higher for an optimally-oriented pad and 1.5× higher for a poorly-oriented pad for a model with 3 laterals/pad than 1 lateral/pad. Although downspacing from 3 to 4 laterals/pad has a greater impact on increasing the cumulative gas production from optimally-oriented pads than downspacing from 1 to 3 laterals/pad, the lower impact on poorly-oriented pads results in a lower total increase the cumulative gas production from the four pads. At the end of the 25-year production history, 9.0% more gas is recovered for the 4 lateral/pad model than the 3 lateral/pad model, which predicts 1.2× more gas than the 1 lateral/pad model. The recovered shale gas exceeds the recovered coal gas after ~7 years of production. The higher contribution of produced coal gas predicted due to downspacing results from a higher contribution of recovered gas from the main coal seam, while the contribution from the minor coal seams is lower. Downspacing has a minimal impact on the cumulative water production; after 25 years of production a difference of 1.0% is predicted between models with 4 and 3 laterals/pad and 1.7% between models with 1 and 3 laterals/pad. While downspacing increases the cumulative water production for the poorly-oriented pads (1.1× for 3 to 4 laterals/pad and 1.3× for 3 to 1 lateral/pad after 25 years), the cumulative water production for the optimally-oriented pads is lower over the majority of the production history (after ~4 years and 3.2% lower after 25 years for 3 to 4 laterals/pad and after ~6 months and 1.1× lower after 25 years for 1 to 3 laterals/pad).

Designing and implementing strategies for coalbed methane field development in complex coal measures require evaluation of the interplay between geology, reservoir properties, well design, completions, and economics. Numerical simulations provide a powerful tool to predict reservoir performance and evaluate different potential development scenarios prior to or during early field development. Optimising field development of the producing Upper Mannville Group coal measures in the Western Canadian Sedimentary Basin in south-central Alberta is particularly challenging due to permeability anisotropy of the coals and contribution of multiple coals seams and organic rich shales to production.

The Mannville coalbed methane resource occurs over a very large geographic area of southern and central Alberta and in equivalent strata in British Columbia (^{1} in the Mannville Formation [_{w} > 0) about 4000 km^{2} in central Alberta^{, }referred to as Corbett (^{2} (2.59 km^{2};

horizontal legs between 1000 and 1500 m in length (

In quantifying reserves and field development in the Mannville producing fairway, reserves and production have generally been considered limited to the main coal seam (1.3 - 4.5 m thick) and in which the horizontal wells are drilled and completed (^{−}^{4} and 0.01 md).

Expanding the models to including multi-lateral well-pads, in this study, the impact of decreasing the spacing between lateral wells (i.e. downspacing) on the production of the Mannville coal measures is investigated through a series of numerical models. This study further investigates the importance of the orientation of the laterals within the anisotropic permeability field and the impact of well interference. Experimental and field data from the Mannville coal measures and adjacent shales in the Corbett region in south-central Alberta are used as model inputs for a general equation-of-state reservoir simulator (CMG-GEM). Our study builds on and extends the work of [

The variation in production of the Mannville reservoir from four orthogonal multi-lateral pads, with spacings of 1, 3, and 4 laterals/pad, was investigated using the commercial CMG’s GEM advanced general equation-of-state compositional simulator to understand the impact of well spacing and orientation (

average values (

Similar to Bustin and Bustin (2017), the depth and thickness of the horizontally stacked coal seams in the models were determined from interpretations of logs from well 16-10-62-06W5 (_{w} > 0) Mannville Group is in the adsorbed state (i.e. no free gas) and the gas in productive area is almost entirely methane with at most a few percent carbon dioxide, while the cleats and fractures are 100% water-saturated (Bustin and Bustin, 2016a; 2017). As a consequence of the symmetry of the model, the production results for pads 1 and 2 (pad1 and pad2) are essentially equal (<0.5%), as are the results for pads 3 and 4 (pad3 and pad4). Therefore, only the results from pad1 and pad3 are discussed.

The gas and water production from a multi-well pad model with one lateral per pad over a 25 year history is first presented, followed by the results from a multi-well pad model with three laterals per pad, and then with four laterals per

Parameter | Reservoir | Coal | Shale | |||
---|---|---|---|---|---|---|

n | Ave | n | Ave | n | Ave | |

Temperature ˚C | 130 | 42 | ||||

Pressure gradient kPa/m | 279 | 8.2 | ||||

Water saturation % | 99 | |||||

Crit water saturation % | 60 | |||||

Bottom hole pressure kPa | 200 | |||||

Density g/cc | 354 | 1.4 | 35 | 2.2 | ||

Langmuir volume cc/g | 45 | 13.7 | 12 | 1.5 | ||

Langmuir pressure MPa | 45 | 5.7 | 12 | 6.2 | ||

Matrix perm md | 1e−3 | 1e−5 | ||||

Diffusion cm^{2}/s | 0.05 | 8e−3 | ||||

Matrix porosity %^{a} | 1e−4 | 1e−4 | ||||

Eff fracture spacing m | 0.5 | 10 | ||||

Max horiz fracture perm md | 110 | 3.8 | 1e−3 | |||

Min horiz fracture perm md | =K_{max}/3 | =K_{max} | ||||

Vert fracture perm md | =K_{max}/3 | =K_{max}/10 | ||||

Fracture porosity % | 0.01 | 1e−4 |

^{a}Note that the matrix porosity values listed above were assumed during the modelling, due to the bound matrix water (matrix S_{w} assumed to be zero by the model), and are not the measured values.

Seam | 16-10-62-6w5 | |
---|---|---|

Depth (m) | Thick (m) | |

U1 | 945.3 | 0.9 |

U2 | 957.5 | 0.7 |

U3 | 959.3 | 0.7 |

M | 980.0 | 4.0 |

L1 | 986.0 | 1.8 |

L2 | 994.6 | 1.0 |

pad. The impact of downspacing on the gas and water production, the produced coal gas versus produced shale gas, and variations in produced gas between the main and minor coal seams are then discussed.

The multi-well pad model with a well spacing of 1 lateral/pad, consists of two 900 m laterals through the main Mannville coal seam optimally-oriented in the direction of maximum coal fracture permeability (pad3 and pad4;

As a consequence of the anisotropy of the coal fracture permeability, the initial peak gas production rate is 1.5× higher from the optimally-oriented lateral at pad1 than the poorly-oriented lateral at pad3 (red versus blue solid curves in

The greater impact of well interference on the poorly-oriented lateral at pad3 than the optimally-oriented lateral at pad1 for the 1 lateral/pad model results in faster dewatering for pad3 and an increasing difference in cumulative water production between the laterals to 2.7× after 25 years of production (red versus blue solid curves in

The multi-lateral, multi-well pad model with 3 laterals/pad consists of one 900 m

lateral (well1), either optimally-oriented (for pad1,

The main lateral, optimally-oriented with respect to the coal fracture permeability anisotropy, on a pad with a 3 laterals/pad well spacing (well1 on pad1 or pad2) is predicted to produce a 2.4× higher initial peak gas production rate and a maximum of 2.7× more cumulative gas production at the end of the 25 year history than a 45˚ lateral (well2 on pad1; red versus orange curves in

Although the 45˚ laterals are more optimally-oriented with respect to the coal fracture permeability anisotropy than the poorly-oriented well1 at pad3, the longer length of the poorly-oriented well1 results in a 1.6× higher initial peak gas production rate (blue versus light blue curves in

The optimally-oriented well1 at pad1 predicts a 1.5× higher initial peak gas production rate (red versus blue curves in

The initial peak gas production rate for a 45˚ lateral at pad3 is very slightly (~10%) lower than predicted for a 45˚ lateral at pad1 (light blue versus orange curves in

The three laterals at pad1 predict a 1.2× higher initial peak gas production rate than the three laterals at pad3 (green solid versus dashed curves in

The faster drainage from the longer more optimally-oriented well1 at pad1 predicts a maximum of 4.3× more produced water than well2 at pad1 at the end of the 25 year history (red versus orange curves in

maximum of 1.8× more produced water after ~2.5 years of production than the more optimally-oriented, but shorter well2 at pad3 (blue versus light blue curves in

The faster dewatering of the poorly-oriented well1 at pad3 than the optimally-oriented well1 at pad1 for the 3 laterals/pad model increases the difference in cumulative water production between the main laterals, such that well1 at pad1 produces 3.1× more water at the end of the 25 year history (blue versus red curves in

The well geometry for the multi-lateral, multi-well pad model with 4 laterals/pad consists of one 900 m lateral through the main seam (well1) and three branch laterals with lengths of 610, 640, and 670 m and at angles of 38˚, 63˚, and 18˚ from the main lateral (well2, well4, and well3) at each of the four pads (

The initial peak gas production rates predicted from the four laterals at pad1 are higher for the more optimally oriented wells (

Well3 at pad1, with longer length, more optimal orientation, and lower interference from adjacent pads (i.e. pad3 and pad4) predicts a higher initial gas

production rate and higher cumulative gas production than well2 and well4 at pad1. The initial gas production rate for well3 is 1.2× higher than well2 (orange versus blue curves in

The more optimal orientation of well2 than well4 results in well2 having a 1.1× higher initial gas production rate (blue versus light blue curves in

throughout the 25 year history, slightly decreasing the difference in cumulative gas production between the wells (1.5% after 25 years of production).

The more optimally oriented laterals at pad1 predict higher water production than other wells. The faster drainage, due to the longer length and more optimal orientation, of well1 at pad1 predicts a maximum of 1.9× more produced water after ~13 years (4660 days) of production than well3, the next most optimally oriented lateral at pad1 (red versus orange curves in

Well3, the second most optimally oriented lateral at pad1, predicts a maximum of 2.1× higher cumulative water production than well4 after 25 years of production and 1.6× higher cumulative water production than well2 after ~17.5 years (6420 days) of production (orange versus light blue and blue curves in

At pad3, well4 has the most optimal orientation with respect to the coal fracture permeability and predicts the highest initial peak gas production rate; however, the poorly-oriented, but longer, main lateral, well1 predicts the highest cumulative gas production over the majority of the 25 year production period. While, the initial peak gas production rate for well4 is 1.3× higher than predicted for well2 and well3, the cumulative gas production is only slightly higher after 25 years of production (1.9% higher than well2 and 4.3% higher than well3; light blue versus blue and orange curves in

The initial peak gas production rate for well4 is also slightly higher (2.7%) than predicted for the longer, but poorly-oriented main lateral, well1 (light blue versus red curves in

The initial peak gas production rate for well1 is 1.2× greater than well2 and 1.3× greater than well3 and the cumulative gas production is a maximum of 1.3×

greater than well2 and 1.5× greater than for well3 (red versus blue and orange curves in

The shorter, but more optimally-oriented lateral, well2, predicts a slightly (4.6%) higher initial peak gas production rate than well3 (blue versus orange curves in

The longest lateral at pad3, well1, which dewaters the fastest, predicts the highest cumulative water production until ~17 years (6300 days) of production, when the cumulative water production becomes lower than predicted for well4, the most optimally oriented lateral at pad3, which dewaters the slowest. The cumulative water production predicted for well1 is a maximum of 1.4× higher than for well4 after ~2 years (800 days) of production and a maximum of 3.2% lower than well4 at the end of the 25 year history (red versus light blue curves in

The water production from well2 and well3 are similar over the 25 year history, with a maximum difference of 4.7% after ~2.5 years (990 days) of production. Initially, well2 predicts the lowest cumulative water production on pad3; however, the cumulative water production from well3 is 0.5% lower than well2 at the end of the 25 year history (orange versus blue curves in

After 25 years, the cumulative water production predicted from well2 and well3 is a maximum of 1.2× lower than well4 and a minimum of 1.2× lower than well1 (

The optimally-oriented main lateral at pad1 predicts a 1.5× higher peak gas production rate than the poorly-oriented main lateral at pad3 (red curve in

The more optimally-oriented well3 at pad1predicts a 1.4× higher peak gas production rate than for well3 at pad3 (orange curve in

Well4 is more poorly-oriented at pad1 resulting in a 1.3× lower peak gas production rate than at pad3 (light blue curve in

The difference in orientation is smallest between well2 at pad1 and at pad3 than the other laterals. Although the slightly more optimal orientation of well2 at pad1 (~40˚ from optimal) than pad3 (~50˚ from optimal) results in a 1.1× higher peak gas production rate, the gas production rate is lower after ~5 days, due to the faster dewatering of pad3 than pad1 (blue curve in

The lateral with the highest cumulative gas production for pad1, well1 predicts 2.1× higher cumulative gas production than well2, the lateral with the lowest cumulative gas production for pad1, at the end of the 25 year production history. In comparison, well1 at pad3, which predicts the highest gas production, predicts 1.3× higher cumulative gas production than well3. The greater variation in cumulative gas production from the laterals at pad1 than pad3 and the prediction that well3 has the second highest gas production at pad1, but the lowest at pad3 results from the higher gas production predicted for well2 and well4 at pad3 than pad1 combined with the slightly lower cumulative gas production predicted for well3 at pad3 than pad1.

The four laterals at pad1 predict a slightly (4.5%) higher peak gas production rate than the laterals at pad3 (red solid versus dashed curves

The greater drainage and slower dewatering from the optimally-oriented well1 at pad1 predicts a maximum of 3.1× higher cumulative water production at the end of the 25 year history than predicted for the poorly-oriented well1 at pad3 (red curve in

For a pad with an optimally-oriented main lateral (i.e. pad1 and pad2), the model with 3 laterals/pad predicts a 1.9× higher peak gas production rate than the model with 1 lateral/pad; however, the faster dewatering for the 3 laterals/pad model results in lower gas production rates than the 1 lateral/pad model after ~6 years (2145 days) of production (blue versus green solid curves in

pad1 to 8.3% after 5 years of production and 4.2% after 25 years of production (green versus red solid curves in

Downspacing has a greater impact on increasing the gas production from pads with the poorly-oriented main laterals (i.e. pad3 or pad4). The initial peak gas production rate predicted from pad3 for the model with 3 laterals/pad is 2.3× higher than predicted from pad3 for the 1 lateral/pad model (blue versus green dashed curves in

The four pads in the 3 laterals/pad model predict a 2.1× higher peak gas production rate as a result of downspacing from a 1 lateral/pad spacing (green versus blue curves in

Downspacing from 1 to 3 laterals/pad predicts a 1.9× higher initial water production rate from pad1 (blue versus green solid curves in

maximum of 3.2% higher than for the 4 laterals/pad model (red versus green solid curves in

Downspacing from a 1 to 3 lateral/pad spacing results in a 2.1× higher initial water production rate from pad3 (blue versus green dashed curves in

The initial water production rate from the four pads for the 3 laterals/pad model is 2.0× higher than for the 1 lateral/pad model and the difference in cumulative water production decreases to 1.7% after 25 years (green versus blue curves in

The recovered shale gas from the four well pads with a 1 lateral/pad spacing exceeds the total recovered coal gas after ~7 years of production resulting in a ratio of recovered shale to coal gas of 2.4 after 25 years of production (solid versus dotted blue curves in

lower ratio after 25 years) and the ratio for the 3 laterals/pad model is lower than the 4 laterals/pad model after ~2 years of production (0.65% lower after 25 years). The recovered shale gas; hence, exceeds the coal gas slightly earlier due to downspacing (~7 years for all three models;

After 25 years of production, the main coal seam in the 1 lateral/pad model contributes 2.6× more recovered gas than L1, 6.1× more than L2, 13× more than U3, 14× more than U2, and 16× more than U1 (

Downspacing from 3 to 4 laterals/pad, similarly to downspacing from 1 to 3 laterals/pad, results in a higher contribution of recovered gas from the main coal seam and lower contributions from the minor coal seams (

Time | 1 lateral/pad model | |||||
---|---|---|---|---|---|---|

U1 | U2 | U3 | L1 | L2 | M | |

1 mon | 0.40 | 0.089 | 0.31 | 3.2 | 0.49 | 96 |

1 | 0.93 | 0.71 | 0.95 | 17 | 3.5 | 77 |

5 | 1.1 | 1.8 | 2.0 | 21 | 6.9 | 67 |

15 | 2.4 | 3.2 | 3.4 | 22 | 8.7 | 60 |

25 | 3.5 | 4.1 | 4.3 | 22 | 9.3 | 57 |

3 laterals/pad model | ||||||

1 mon | 0.2 | 0.044 | 0.15 | 3.4 | 0.24 | 96 |

1 | 0.62 | 0.60 | 0.81 | 16 | 3.2 | 79 |

5 | 1.0 | 1.7 | 1.9 | 21 | 6.4 | 69 |

15 | 2.3 | 3.1 | 3.3 | 21 | 8.3 | 62 |

25 | 3.3 | 3.9 | 4.1 | 21 | 8.9 | 58 |

4 laterals/pad model | ||||||

1 mon | 0.16 | 0.035 | 0.14 | 3.4 | 0.19 | 96 |

1 | 0.57 | 0.60 | 0.78 | 16 | 3.1 | 79 |

5 | 0.98 | 1.6 | 1.8 | 20 | 6.2 | 69 |

15 | 2.2 | 3.0 | 3.3 | 21 | 8.1 | 62 |

25 | 3.3 | 3.9 | 4.1 | 21 | 8.8 | 59 |

recovered gas that is greater and occurs earlier for seams closer to the wellbore (1.4× difference for main and L1 after 1 month compared to 1.4× for L1 after ~1 months, 1.2× after ~6 months for L2, 1.1× after ~9 months for U3, 1.2× after ~1 year for U2, and 1.1× after ~11 years for U1;

The recovered gas from the topmost, but thickest of the upper seams, U1, is initially greater than the gas recovered from U2 and U3 for all three models with varying well spacing (

The reservoir drainage volumes, approximated by the drawdown in reservoir pressure, for the models with one, three, and four laterals per pad after 1, 5, and 25 years of production are compared in Figures 20-22. The comparison shows the increase in reservoir pressure drawdown in the region around the pads, due to infill drilling. While the drainage volume is only slightly greater for the 3 laterals/pad model than the 1 lateral/pad model, the higher coal and shale recovery for the 3 laterals/pad model is apparent from the greater change in matrix pressure in the section of the model containing the well pads. The higher initial impact of downspacing on the shale gas recovery than coal gas recovery is mainly due to the increased drainage of the interbedded shale layers, S3 and S4, adjacent to the main coal seam. After 5 years of production, increasing the number of laterals per pad from 1 to 3, increases the ellipsoidal area of significant drainage (decrease in reservoir pressure > 500 kPa) by 4.9% and increasing the number of laterals from 3 to 4 increases the drainage area by 1.3% (2.93 × 10^{6} m^{2} versus 3.08 × 10^{6} m^{2 }versus 3.12 × 10^{6} m^{2}). For all three models, the significant drainage is restricted to between the top of U2 and the 20 m of shale below L2 after 5 years of drainage (see ^{6} m^{2} versus 6.42 × 10^{6} m^{2 }versus 6.44 × 10^{6} m^{2}). After 25 years of production, significant drainage also occurs in U1 and the 20 m of shale above U1, as well as in the 60 m of shale below L2.

Numerical simulations of production from coal measures with anisotropic permeability provide insights to development strategies that are otherwise not readily visualised or predictable. The complex interplay between water production, gas production, contribution from multiple seams and organic rich shales, and impact of well interference, all combined with anisotropic fracture permeability are difficult to predict and some results are counterintuitive. Although no numerical model at this time can truly simulate the actual complexities of the geology, the results using the metrics from the Mannville Group in the producing

fairway are instructive and provide a foundation for spacing units, lateral lengths and orientation.

The producability of the gas stored within minor coal seams over- and under-lying the main Mannville coal seams, as well as the gas stored in the shale beds which interbed and over- and under-lie the coal seams has been investigated through a series of numerical simulations of four well-pads on the corners of square mile of land (1600 × 1600 m) with decreasing well spacing (from one, three, to four laterals per pad). The cumulative gas production for the 4 laterals/pad model is initially a maximum of 1.6× higher than for the 3 laterals/pad model. The difference in cumulative gas production between the models with 4 and 3 laterals/pad decreases over the production history and after 25 years, 9.0% more gas is recovered (black bar in white box in

The initial water production rate from the four pads for the 4 laterals/pad model is 1.7× higher than from the four pads for the 3 laterals/pad model, which is in turn, 2.0× higher than from the four pads for the 1 lateral/pad model. However, downspacing has less than a 10% impact on the cumulative water production after ~5 years of production. The cumulative water production predicted from the 4 laterals/pad model is 1.0% higher at the end of the 25 year history than the 3 laterals/pad model (black bar in white block in

After 25 years of production, 61% of the recovered gas is produced from the two optimally-oriented laterals at pad1 and pad2 for the 1 lateral/pad model,

52% for the 3 laterals/pad model, and 50% for the 4 laterals/pad model, due to the assumed fracture permeability anisotropy. Downspacing has a greater impact on increasing the gas production from pads with the poorly-oriented main laterals (pad3) than from the pads with the optimally-oriented main laterals (pad1). The 4 laterals/pad model has a 1.5× higher initial peak gas production rate from pad1 and a 4.2% higher cumulative gas production at the end of the 25 year history than the 3 laterals/pad model (red bar in white box in

The initial water rates from pad1 and pad3 are 1.7× higher due to downspacing from 3 to 4 laterals/pad and are 1.9× higher from pad1 and 2.1× higher from pad3 due to downspacing from 1 to 3 laterals/pad. Similarly to the results for the gas production, downspacing has little impact on the cumulative water production from the pads with the optimally-oriented laterals (pad1) over the 25-year production history. The cumulative water production from pad1 for the 3 laterals/pad model is higher than predicted for the 4 laterals/pad model after ~4 years of production and 3.2% higher at the end of the 25 year history (red bar in white box in

Overall, the results demonstrate that the over and underlying minor coal seams and interbedded organic-rich shales contribute significantly to the producible gas. During the 25-year production history, the higher contribution of produced coal gas predicted due to downspacing results from a higher contribution of recovered gas from the main coal seam, while the contribution from the minor coal seams is lower. The recovered shale gas exceeds the recovered coal gas after ~7 years of production for the models.

In this paper, we have only considered the impact of pad design on production since economic considerations are dynamic and area specific. Optimising well design and spacing units in field development cannot be made in isolation from economics. In this study, we have not added the layer of complexity of economics. Downspacing will always enhance short term production rates, but the net present value of the production has to be weighed against the associated additional capital and operating costs.

This study was made possible through access to data and money from Trident Exploration Corp. and the authors would like to thank Virgil Todea. We are also thankful to CMG for their ongoing support.

Bustin, A.M.M. and Bustin, R.M. (2018) Importance of Well Spacing and Orientation for Multi-Lateral Pads on Production: Learnings from Production Analysis and Numerical Modelling of the Mannville Coal Measures, South Central Alberta. Engineering, 10, 368-398. https://doi.org/10.4236/eng.2018.107027