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SUMMARY AND CONCLUSIONS
Trends in Qh/Qv
• Trends in the relative production of horizontal versus vertical wells, Qh/Qv, to a particular parameter, e.g. length, can be dependent on the other parameters at which the trends are determined.
• Near the optimal set of parameters for maximizing Qh/Qv, Sm-h and Hh/Hv have the dominant impact with Hh, D, L and kv/kh, having secondary impact. At skins greater than 2, Qh/Qv becomes less than 3 and there is less than a 25% gain in Qh/Qv when extending the length from 2000 to 6000 ft.
• The effective mechanical skin in a horizontal well damaged to the same extent as that for a vertical well can be estimated by multiplying the vertical well skin by the factor h/L√(kh/kv), which usually results in lower effective skins for the horizontal well (e.g. Sm-h = 0.45 to 1 could correspond to typical skins of 4.5 to 10 observed in vertical CBM wells drilled underbalanced).
• Horizontal well production can be less than that for a vertical well when Hh/Hv < 0.2 and Sm_h > 2.
• Hh/Hv is important in the prediction of the upside of a horizontal well, compared with offset vertical wells, and it is critical if skin < 1 where there can be strong dependence of Qh/Qv on Hh/Hv. A higher ratio of Hh/Hv is better, and a single seam is best (e.g., Arkoma basin).
• Qh/Qv will be independent of depletion as long as both the horizontal and vertical wells have the same reservoir and flowing wellbore pressures and if reservoir permeabilities remain constant. Under these conditions, it can be inferred that the horizontal well will deplete at a more rapid rate, since at a given depleted reservoir pressure, its rate is always greater. This seems in accord with field data.
• In wells with Hh/Hv less than one, total cumulative production is greater for the vertical well because it captures greater pay. Therefore, laterals in more than one seam should be considered in order to produce at higher rates, and to more fully recover reserves.
Wellbore Flow Effects --Wellbore flow effects can have significant impact on horizontal well performance. • At higher reservoir pressures (500-800 psi), the impact of wellbore diameter on production is minimal except for wells with downdip geometries in excess of 15 degrees, where a 3-inch wellbore gives higher gas rates than a 6-inch wellbore.
• At a low reservoir pressure of 200 psi, a 3-inch diameter wellbore gives higher gas rates than a 6-inch diameter wellbore for all geometries tested (flat, undulating, and downdip). At downdip angles of 15 degrees or greater, gas rates were zero in both diameter wellbores.
• The higher gas production rates in the 3-inch diameter wells are the result of higher wellbore velocities that transport the water better.
• For wells producing significant water throughout their lifetime, a 3-inch (or 3.5-inch) horizontal gives mostly higher gas rates than a 6-inch horizontal, especially during the lower critical under-saturated period.
• At low reservoir pressure of 200 psi, a 2000 ft well gives higher gas rates than a 6000 ft well if both wells are undulating. The difference is greater for a 6-inch well and there is no advantage of longer length in this scenario.
• At high to medium reservoir pressure (500-800 psi), the impact of build radius on production is minimal (with well skins of 1 or greater).
• At low reservoir pressure (200 psi), short radius drilling will still allow production whereas medium radius will not.
• At low reservoir pressure (200 psi), zero radius drilling improves production, but only by ~15%. Since this requires two vertical wellbores, the cost-benefit does not seem warranted compared with small radius drilling.
• At high reservoir pressure (800 psi), drilling updip with a medium build radius can improve production, but it’s a very small improvement (~5%).
• At low reservoir pressure (200 psi), production from a long lateral (6000 ft) is only marginally better than that from a short well (2000 ft) if the well is damaged (skins >1).
Effect of Wellbore Diameter on Horizontal Wellbore Stability
• Increasing hole diameter from 3” to 6” could have a small but significant reduction in hole stability during CBM production and depletion.
• Based on lab data the TWC strength could be reduced by ~11.5% (based on TWC tests of Castlegate and Berea sands).
• The strength may be reduced even more for coals, since they are naturally fractured.
• A 6” horizontal is predicted to collapse earlier than a 3” horizontal, for example for HVA coal at 2800 ft, the maximum allowable drawdown is reduced from 1260 psi to 1140 psi and the maximum allowable depletion is reduced from 1220 psi to 880 psi.
• A similar situation is expected to apply for wellbore stability during drilling (by analogy)
• In weaker coals, such as MV and LV coals, wellbore stability can be expected to be even more problematic.
• A liner is nearly always recommended in such coals, and the best horizontal well is the smallest diameter well that can accept a liner (a smaller diameter well will also carry water better and produce at higher gas flow rates).
• Too much underbalance or drawdown (or surging) can cause shear failure, and fines plugging. It appears that the optimum is to drill slightly underbalanced.
总结和结论
Qh/Qv趋势
水平井和垂直井相对产量趋势，Qh/Qv是一个特殊参数，依赖于已经确定趋势的其他参数，比如长度。
作为最优参数组合，Sm-h和Hh/Hv对Qh/Qv最大化有决定性的影响，Hh, D, L和kv/kh起次级作用。当表皮大于2时，Qh/Qv小于3，当井长度从2000ft到6000ft变化时，Qh/Qv占的比例小于25%。
损坏程度同垂直井相同的水平井有效机械表皮，可乘以受h/L√(kh/kv)系数控制的垂直井表皮估算出来，常导致水平井低的有效表皮（比如，Sm-h = 0.45到1相当于在CBM负压垂直井中获得的标准表皮4.5 到10）。
当Hh/Hv < 0.2和Sm_h > 2时，水平井产量少于垂直井产量。
相对于偏心垂直井，Hh/Hv在水平井上部预测中很重要。如果在Qh/Qv对Hh/Hv有较强的依赖处，表皮< 1，Hh/Hv更是关键中的关键。Hh/Hv越大越好，如果是单层会更好（比如，Arkoma盆地）。
只要水平井和垂直井拥有相同的油藏、井内流压，油藏渗透率保持为常数，Qh/Qv将不受放空影响。在这些条件下，可以推断水平井放空速度比较快，因为在给定放空油藏压力情况下，其速度一直都很高。这完全符合油田数据。
在Hh/Hv小于1的井中，垂直井的总累积产量较大，因为垂直井有多套生产层系。因此，为了获得较高的产气速率和采收率应该考虑多个层系的侧向钻井。
井筒流动作用—井筒流动作用对水平井生产有重要影响。
油藏压力为高压时(500-800 psi)，井筒直径对产量的作用极小，但不包括几何形状为角度大于15度的下倾， 其3英寸井径产气速率比6英寸高。
油藏压力为200 psi的低压时，对各种几何形状（平的、丘状、下倾）的井测试，3英寸的井的产气速率比6英寸的高。当下倾角度为15度或更大时，在两种井径中的产气速率都为零。
3英寸井径的井具有较高的产气速率，这是由于井筒中水流的速度较高。
对于主要产水的井而言，3英寸（或3.5英寸）的井产气速率比6英寸的井高，特别是在主要的低未饱和期间。
油藏压力为200 psi的低压时，如果井为丘状起伏，2000 ft的井产气速率比6000 ft的井还高。对于6英寸的井而言，差别太大，在这种情况下长度越长反而没有优势。
油藏压力在中压到高压范围内时 (500-800 psi)，增斜作用对产量的影响最小（井表皮为1或大于1）。
在低压油藏(200 psi)，短半径钻井仍可有产量，而中等半径则没有。
在低压油藏(200 psi)，零半径钻进可以改善产量，仅有约15%。因为这个方法需要两口垂直井，所以从成本利益上来说，相对小井径钻井该方法看起来是不会批准的。
在高压油藏中（800 psi），以中等增斜半径钻进上倾可以增加产量，但量比较小（约5%）。
在低压油藏中(200 psi)，如果井被损坏（表皮>1），具有长侧向井（6000ft）的产量仅在边缘部分比短侧向井(2000 ft)好。
井径对水平井稳定性的影响
在CBM生产和放空过程中，井径从3”到 6”增加，井眼稳定性会轻微降低，但意义很重大。
基于实验室数据TWC强度大约减少11.5%（基于Castlegate和Berea砂岩TWC测试）。
煤层强度降低更多，因为煤层是自然破裂的。
在6”时先坍塌，而在3”时后坍塌。比如HVA2800 ft处煤层，最大允许压降为1260 psi到1140 psi，最大允许放空为1220 psi到880 psi。
在钻井过程中期望相同条件适用于井筒的稳定性（模拟）
在较差的煤层中，比如MV和 LV煤层，井筒稳定性会出现很多问题。
在这样的煤层中，常推荐使用衬管，最好的水平井是可以用衬管的具有最小直径的井（小井径的井产水比较多，并具有较高的产气速度）。
负压或压降（波动）太多导致剪切破坏，细粒物质堵塞。最优化方案是用较小的负压钻井。
