欠饱和煤层气藏储量平均地层压力和采出率计算方法

Methods for calculating reserves, average reservoir pressure and gas recovery ratio for under-saturated coalbed methane reservoirs

  • 摘要: 原始地质储量是煤层气开发的物质基础,平均地层压力和采出率是煤层气开采的主要评价指标。目前欠饱和煤层气藏原始地质储量评价方法多基于煤层气和水相物质平衡原理,考虑孔隙率和饱和度的变化,应用拟偏差系数Z*将吸附气等效为游离气,所需参数众多,计算过程复杂;煤层气藏平均地层压力计算方法除了考虑气相的产出,还考虑了水相的产出,在计算过程中需要循环迭代计算气体偏差系数Z,计算过程繁琐。实际上,对于欠饱和煤层气藏,无需具备众多参数,计算过程也无需循环迭代计算气体偏差系数。首先基于欠饱和煤层气藏吸附气物质平衡原理,直接采用吸附气剩余储量与压力之间的关系,包括Langmuir-Freundlich(L-F)吸附模型和基于微孔填充的Dubinin-Astakhov(D-A)吸附模型,建立了欠饱和煤层气藏物质平衡方程;然后基于此物质平衡方程,进行线性化处理,形成了欠饱和煤层气藏中煤层气原始地质储量的评价方法、平均地层压力计算方法和煤层气采出率计算方法;最后进行方法验证和实例应用。研究表明:提出的欠饱和煤层气藏储量和平均地层压力计算方法仅需少量吸附模型参数和生产过程中2次以上的测压数据及对应的累计产气量数据,即可评价出欠饱和煤层气藏中煤层气的原始地质储量和平均地层压力,并预测给定废弃压力下的煤层气采出率,计算过程简便,所需参数较少,节省了运算所需时间,并且精度满足矿场要求,便于大范围推广应用。基于概念数值模拟模型生成的生产动态数据,应用提出的储量计算方法评价的储量与数值模拟输出结果的相对误差为–0.762 577%,评价的拟稳态期平均地层压力与数值模拟输出结果的相对误差均在–0.60%~0.25%,验证了本方法的合理性和可靠性。对不同吸附模型的实例井进行应用并分析,储量评价结果与实际矿场认知相符;计算得到的平均地层压力曲线穿过了矿场实际关井测压压力点;给定煤层气藏废弃压力2、1.5、1 MPa,计算出煤层气井A的采出率分别为46.65%、55.54%和66.65%,煤层气井B的采出率分别为57.49%、65.05%和73.96%,对现场开发有重要指导意义。对于储量已知的欠饱和煤层气藏,无需实测平均地层压力数据即可计算出煤层气藏平均地层压力,相比于常规测量平均地层压力方法,本方法极大地提高了计算效率。研究成果可用于评估煤层气剩余储量、评价煤层气井产能和判断井间干扰情况,对气井生产动态分析、开发方式论证及排采制度优化等有非常重要的理论与现实意义。

     

    Abstract: Original gas in place (OGIP) is the material foundation for coalbed methane (CBM) development, while the average reservoir pressure and recovery factor are the primary evaluation metrics for CBM extraction. Currently, the evaluation methods for OGIP in undersaturated CBM reservoirs predominantly rely on material balance principles incorporating both gas and aqueous phases, considering changes in porosity and saturation. These conventional approaches employ pseudo-deviation coefficient Z* to equivalate adsorbed gas to free gas, requiring numerous parameters and involving complex calculations. Traditional average pressure calculation methods additionally consider aqueous phase production, necessitating iterative computations of gas deviation factor Z, making the process cumbersome. In reality, for undersaturated CBM reservoirs, neither numerous parameters nor iterative calculations of the gas deviation factor are fundamentally required. This study first establishes a material balance equation for undersaturated CBM reservoirs based on the adsorbed gas material balance principle, directly utilizing the relationship between remaining adsorbed gas reserves and pressure. This includes the Langmuir-Freundlich (L-F) adsorption model and the Dubinin-Astakhov (D-A) adsorption model based on micropore filling. Subsequently, the material balance equation is linearized to develop evaluation methods for OGIP, average reservoir pressure, and recovery factor in undersaturated CBM reservoirs. Finally, the methods are validated and applied in case studies. Research demonstrates: The proposed methods for calculating reserves and average reservoir pressure in undersaturated CBM reservoirs require only a few adsorption model parameters, along with pressure data from two or more well tests and corresponding cumulative gas production data. These methods enable the evaluation of OGIP and average reservoir pressure, as well as the prediction of recovery factor at a given abandonment pressure. The calculation process is simple, requires fewer parameters, saves computational time, and meets field accuracy requirements, making it suitable for widespread application. Using production data generated from a conceptual numerical simulation model, the relative error between the reserves evaluated by the proposed method and the numerical simulation results is –0.762 577%. The relative error for the evaluated average reservoir pressure during the pseudo-steady state phase falls within –0.60% to 0.25%, confirming the rationality and reliability of the method. Application and analysis of real-world wells with different adsorption models show that the reserve evaluation results align with field observations. The calculated average reservoir pressure curve passes through the actual shut-in pressure measurement points. At abandonment pressures of 2, 1.5, 1 MPa, the calculated recovery factors for Well A are 46.65%, 55.54%, and 66.65%, respectively, while for Well B, they are 57.49%, 65.05%, and 73.96%, providing significant guidance for field development. For undersaturated CBM reservoirs with known OGIP, the average reservoir pressure can be calculated without actual pressure measurement data. Compared to conventional methods, this approach significantly improves computational efficiency. The research findings can be applied to assess remaining CBM reserves, evaluate well productivity, and diagnose inter-well interference. They hold substantial theoretical and practical significance for production performance analysis, development strategy optimization, and production system adjustment.

     

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