Search

As an unconventional gas resource, coalbed methane (CBM) reservoir has unique flow mechanism and production scheme compared with conventional and other unconventional gas reservoirs. At present, many investigators have done a lot of researches on CBM productivity prediction. However, few studies consider variable mass flow within hydraulic fracture and hydraulic fracture conductivity decrease in the model. Thus in order to accurately forecast gas productivity, the pressure propagation process, gas-water two phase flow in coal formation, stress sensitivity and coal matrix shrinkage in cleat system, variable mass flow within hydraulic fracture, and fracture conductivity decrease should be considered simultaneously when establishing gas production model of CBM wells. In this work, firstly the pressure propagation model is established for vertically fractured CBM wells and vertical CBM wells without fracturing. Secondly, the pressure drop model in the hydraulic fracture is developed considering variable mass flow and conductivity decrease in the hydraulic fracture. Thirdly, based on the pressure propagation model, the dynamic permeability model considering stress sensitivity effect and matrix shrinkage effect, the pressure drop model in the hydraulic fracture considering variable mass flow and conductivity decrease in the hydraulic fracture, a multi-factor coupled CBM well productivity equation is established and solved using numerical methods. Fourthly, the proposed models are validated by numerical simulation and compared with numerical simulation when variable mass flow and conductivity decrease in the hydraulic fracture are considered. Finally, the main factors influencing the productivity of CBM wells are analyzed. Excellent agreements between gas (water) production rate by the proposed models and simulations are obtained when variable mass flow and conductivity decrease in the hydraulic fracture are not considered, indicating that the degradation form of the proposed gas productivity model for CBM wells is rational and accurate to predict the gas production of CBM wells. More importantly, when variable mass flow and conductivity decrease in the hydraulic fracture are considered, the proposed model matches the actual data better than the commercial simulator, exhibiting the superiority of the proposed model in some cases. Preliminary study results show that: the cumulative gas production of CBM wells (CGPC) decreases sharply when permeability is less than 0.5 mD. CGPC increases with increasing the hydraulic fracture length but reaches a plateau after a given value. The stress sensitivity of the cleat system decreases early production, while, the matrix shrinkage improves the productivity of CBM wells at late production stage. The permeability decreasing index of the hydraulic fracture directly leads to the rapid decrease in gas production rate of CBM wells. Because the pressure propagation process, the dynamic permeability, the variable mass flow within the hydraulic fracture, and fracture conductivity decrease are accounted for in the productivity equation of CBM wells, it can predict the actual productivity of CBM wells more accurately and provide a theoretical basis for the development of CBM reservoirs.

To date, the development of coalbed methane (CBM) reservoirs has attracted a great deal of attention due to its considerable perspective reserves. As a result, nearly all research aspects of CBM reservoirs have been extensively investigated and expect to advance gas production performance as well as associated economic value. Notably, amongst the most significant issue influencing the production performance is the production strategy optimization, which however remains challenging because of the complex time-varying fluid flow performance during the development process of CBM reservoirs. It is always difficult but crucial to shed light on the optimal drawdown pressure within different production scenarios. According to the gas-water two-phase version productivity equations which have been proposed in our previous work, a set of quantified optimization criterion for production strategy within the entire CBM well production process is developed for the first time in this research paper. The proposed optimization criterion contains three procedures: (1) the gas well maintains the bottom-hole pressure (BHP) as critical desorption pressure until the pressure wave propagate to the boundary; (2) the BHP is set as the critical pressure, which is firstly proposed herein and determined by gas phase productivity equation, until the pressure at the boundary become below the critical desorption pressure; (3) the gas well maintains the BHP as the abandonment pressure. In order to clarify the validity of the proposed criterion, we applied the optimization criterion to an actual CBM well located in Hancheng field, China, and found the case with optimized production strategy achieved much better gas recovery compared with that based on the previous production strategy. Moreover, production evaluation work is performed based on the utilization of the proposed optimization method, it indicates that optimized gas production can attain relatively high gas production rate in the future three years. The optimization method possesses simple and easy-operation advantages, which shares great application potential in actual CBM fields and turns out to be practical. In addition, because a practical optimization method for scheduling production strategy of CBM wells has not been proposed before, this work is able to fill the knowledge gap and will contribute to the efficient development of CBM reservoirs.

Precise characterization of dynamic desorption area is crucial for accurate production prediction, production strategy formulation, and well pattern optimization of coalbed methane (CBM) reservoirs. However, little attention has been focused on this topic and a handful of related previous researches suffer some fatal deficiencies. Thus, the objective of this work is to overcome these deficiencies and then extensively investigate the propagation behavior of desorption area during CBM recovery. During depressurization development process of CBM reservoirs, due to the effect of gas desorption, gas saturation takes place in the original water-saturated coal seams, which will decrease the expansion speed of desorption area. Moreover, saturation distribution in the whole coal seam is a dynamic parameter during CBM recovery, which plays an important role for the propagation behavior of desorption area but has not yet been captured in current models. Firstly, pressure-squared concept is utilized to describe pressure distribution within desorption area, which has been considered as an effective method. Secondly, based on the partial differential equation of subface fluid flow accounting for gas desorption, the formulas for pressure-saturation relationship are derived. Finally, according to material balance equation for infinitesimal coal seams, a novel mathematical model for desorption area is developed. Results show that: (a) shape of desorption area will transition from ellipse into a circle with production proceed; (b) matrix shrinkage effect has few influences on the expansion of desorption area at a certain cumulative gas production; (c) rapid decrease of BHP will result in a small desorption area for actual production of CBM wells. The research, for the first time, provides an accurate and fast semi-analytical model to simulate propagation behavior of desorption area. Also, the proposed model is easier to setup and less data-intensive than a numerical simulator. Considering the interests for development of CBM reservoirs, the research can serve as an effective tool for gaining a better understanding of the flow physics in the whole coal seam.

To date, much attention has been focused on the high-permeability CBM reservoirs, which results in ignorance of pressure and saturation gradients in the coal seams of previous productivity equations. However, for the low-permeability CBM reservoirs (

The flowing material balance (FMB) equation is a frequently-utilized engineering tool to extract reservoir information according to production performance of producing wells. At present, it is still significantly challenging to adapt the FMB equation to CBM reservoirs due to the existence of gas-water two phase flow, stress dependence, matrix shrinkage and gas desorption. With all my respect to previous FMB equations for CBM reservoirs, a great deal of attention has been drawn to the single water/gas flow, which can only be applied for early production stage or cannot capture the gas-water two phase flow features of general CBM reservoirs. The most recent and comprehensive research effort of FMB equation for CBM reservoirs is performed by Clarkson and Salmachi (2017), which takes the aforementioned characteristics into account. However, suffering the limitation that the pressure-saturation relationship is not available, Clarkson and Salmachi (2017) assume the saturation and pressure gradients in coal seams are negligible, i.e., the relative permeability is not incorporated in the pseudo-pressure calculation, which will inevitably lead to large deviation compared with the precise results. Notably, during the depressurization development process of low-permeability CBM reservoirs, the pressure and saturation gradients are large enough and cannot be overlooked. Thus, a robust FMB equation for gas-water two phase flow in low-permeability CBM reservoirs is still lacking in the petroleum industry and is significantly necessary to be developed. In this study, the important pressure-saturation relationship is rigorously derived in terms of the conservation of mass and momentum equations, in which the gas desorption, matrix shrinkage and stress dependence are fully coupled. Next, the developed relationship is used to calculate the gas/water phase pseudo-pressure and subsequently the previous FMB equation for CBM reservoirs is modified. Finally, reliability of proposed FMB equation is successfully verified against the numerical simulation with excellent agreements compared with the input reservoir properties. In addition, with the intent of further solidifying the field applicability of the modified FMB equation, the production performance of an actual low-permeability CBM well in Hancheng field, China is analyzed through the proposed FMB equation and desirable interpretation results are achieved. Incorporating the pressure-saturation relationship for the first time, the modified FMB equation can serve as a practical and robust tool to extract valuable information regarding the low-permeability CBM reservoirs.

In the early production stage of coalbed methane (CBM) wells, especially in low permeability reservoirs, the method of shutting in casing annulus is usually adopted. However, the current commercial numerical simulation software fails to predict the dynamic performance of CBM wells under the control of both bottom-hole pressure and casing pressure. In this work, the calculation models of wellbore-pressure distribution and formation pressure distribution are derived firstly. Then, the above two models are coupled with several CBM dynamic performance analysis (CBMDPA) models developed in our previous researches, including pressure propagation model, water/gas productivity equations, dynamic permeability model, and material balance equation. A new CBMDPA program is developed with the coupling model, which can simulate the dynamic production performance of CBM wells after inputting the basic reservoir and fluid parameters, casing pressure, and bottom-hole pressure. Next, the newly developed CBMDPA program is validated against four field cases in China, and excellent agreements are obtained. The inputs of our CBMDPA program include casing pressure, bottom-hole pressure, and some deterministic and uncertain reservoir and fluid parameters. By adjusting the uncertain parameters, the gas production history can be fitted, and the uncertainty on the determination of reservoir properties can be addressed. On this basis, the future gas production is predicted using the determined parameters and the scheduled bottom-hole pressure and casing pressure. Finally, the influence of casing pressure on gas production is studied. Results show that high casing pressure has detrimental impact on the maximum daily gas production, while, it plays a positive role to achieve great desorption area, which will further prolong the stable gas production period. Under the high casing pressure of 2.5 MPa, the maximum daily production is decreased by about 54%, but the stable production stage is prolonged to more than 3000 days. It indicates that an appropriate range for casing pressure is favorable, considering both the accumulative gas production and the desorption area. For the case with representative properties from Muai block, the casing pressure is suggested to be 1–2 MPa, and the range between 1 MPa and 1.5 MPa is recommended for Hancheng block.

A material balance equation (MBE) is usually used to estimate hydrocarbon reserves, to judge driving mechanism, and to predict the dynamic performance of oil and gas reservoirs. Few straight-line methods have been proposed for estimating original gas in place (OGIP) of water bearing gas reservoirs with high water production until now. For this type of gas reservoir, gas and mobile water mostly coexist in the same formation because of low permeability. Lots of water is produced even though there is no bottom or edge aquifer. Thus, the effect of water production on average pressure should not be ignored. In this work, an MBE for water bearing gas reservoirs considering the effects of water compressibility, pore compressibility, and water production, is derived step by step from the basic material balance principle, and the corresponding straight-line reserve evaluation method is developed. Then the proposed reserve evaluation method is validated against a computer modelling group (CMG) simulation case and two field cases using pressure transient analysis (PTA) method in the dynamic data analysis software KAPPA Ecrin. Finally, the necessity and importance of the proposed reserve evaluation method in water bearing gas reservoirs are discussed. Validation cases prove that the proposed straight-line reserve evaluation method for water bearing reservoirs is reliable and rational. The OGIP of water bearing reservoirs can be evaluated directly using the y-intercept divided by the minus slope of the straight line. If ignoring the effect of water production, the OGIP of water bearing gas reservoirs will be underestimated, especially for gas wells with high water production rate and short producing time.

Despite the recent activities in ultra-thick gas reservoirs worldwide, accurate evaluation of gas wells deliverability remains technically challenging. The success of such evaluation efforts relies heavily on proper consideration of the impact of ultra-thick pay zones. Deliverability equations and corresponding test methods are necessary to predict the deliverability of gas wells in ultra-thick gas reservoirs. In this paper, we develop a new model for calculating the pressure drop along the wellbore with varying mass flow rates from gas production profile testing. A new set of deliverability equations is proposed for gas wells in ultra-thick reservoirs. The new equations incorporate production testing data and are applicable to a wide reservoir pressure range. Correspondingly the deliverability test method for ultra-thick gas reservoirs was proposed. The integrated approach of utilizing deliverability equations and the proposed test method were validated against reservoir simulations that incorporate wellbore pressure drop. Good agreements between simulation and current analytical results were obtained for both low-pressure and high-pressure gas reservoirs. It is appropriate to apply the proposed deliverability equations and the corresponding test method to predict the deliverability of ultra-thick gas reservoirs. Further, validations using field data are in progress.

Permeability is a fundamentally important parameter of hydrocarbon reservoir because it significantly impacts well productivity. In laboratories, it is measured under isotropic load which is equal to overburden pressure and it is often assumed to remain unchanged during production. In really however, stress arch forms above the reservoir and the overburden pressure drops during production. Consequently, there is a clear need to illustrate the stress arching effect on the stress sensitivity of permeability and well dynamic performance. Stress arching ratio, which is defined as the change in overburden pressure divided by the change of pore pressure from initial reservoir condition, is calculated for different reservoir shapes in Sulige gas field. Relationship between overburden pressure and effective stress considering stress arching effect in Sulige gas field has been established. Laboratory experiments following reservoir depletion path have been conducted under the stress arching ratio of 0.12 and 0.28 that the reservoir may follow. The results show that the stress sensitivity of permeability greatly depends on stress arching ratio. Permeability measured under nonzero stress arching ratio is larger than that obtained from the conventional experiments with the stress arching ratio of 0 under the same condition. At the pressure drop of 25 MPa, the measured permeabilities increase by 23% and 50% for the stress arching ratios of 0.12 and 0.28, respectively, compared with the values obtained by the conventional experiments when the initial permeability of the core is 0.098 md. In contrast, the permeability shows less dependence on stress arching ratio when the initial permeability of the core is large, such as 7.387 md. Furthermore, the effect of stress arching ratio is introduced into the calculation of well productivity based on the experiment results. The gas well productivities increase by 5.03%, 12.46% and 72.48% for stress arching ratios of 0.12, 0.28 and 1, respectively, when the reservoir initial permeability is 0.098 md. The impact of stress arching ratio on dynamic performance of gas well is generally incorporated via look-up tables of transmissibility multiplier in Eclipse, which is approximate to the ratio of the decreased permeability to the initial permeability for different stress arching ratio. The production decline rate and production decline type are closely related with stress arching ratio when the initial permeability is 0.098 md. This work investigates the stress arching effect on stress sensitivity of permeability for cores with different initial permeabilities. it can provide some insights into gas productivity calculation, production forecasting, and gas recovery determination

Permeability measurement is necessary in oil and gas fields. During the measurement, slippage, rock deformation, and water saturation affect apparent permeability of low permeability sandstones measured by different fluids. It is well known that gas slippage effect is very obvious and crucial in apparent permeability of low permeability sandstones measured for gas. Klinkenberg correlation was proposed to calculate gas permeability and absolute permeability for low permeability sandstones without considering rock deformation and water saturation. Most previous researchers modified the slippage factor b as a function of absolute permeability, porosity, and water saturation. However, few models were proposed for gas permeability calculation, simultaneously considering effects of rock deformation, gas slippage, and water saturation. In this work, Klinkenberg correlation was extended for permeability calculations measured by liquid and gases. The difference between apparent liquid permeability and apparent gas permeability was that gas slippage, which was much more evident from liquid slippage. An apparent gas permeability model was proposed for gas permeability and absolute permeability calculation simultaneously considering rock deformation, gas slippage, and water saturation in low permeability sandstones. The apparent gas permeability is proportional to the term T / p . Both the interception and the slope of the straight line in the T / p – k g plot with Cartesian coordinate were power law functions of net stress and gas saturation. Some experimental data from literature were applied to validate the proposed model. Good agreements between experimental data and those evaluated by the proposed model were obtained. The apparent gas permeability model proposed in this work will be useful to professionals involved in laboratory measurement of low permeability water-bearing rocks, modeling well performance, and gas production forecasting.

A detailed study for production prediction methods under various drainage schedules for under-saturated coalbed methane wells is performed. In terms of the relationship between the value of average reservoir pressure and the critical desorption pressure, whole production life of under-saturated coalbed methane wells is divided into two periods, and the material balance equation in each period is derived respectively. Combining the two-period material balance equation and productivity equation under pseudo-steady state, a novel production prediction method is developed. Excellent agreements between predicted water/gas production rates from the proposed method and those from numerical simulator clarify the reliability successfully. Results demonstrate that (a) matrix shrinkage effect and effective permeable capability can significantly contribute to the production rise; (b) For the drainage schedule (FWFB), with the increase of the fixed water production rate, the drainage period will shorten; (c) For the drainage schedule (RDFB), sharp decrease of formation pressure will take place.