Data-Based Smart Model for Real Time Liquid Loading Diagnostics in Marcellus Shale via Machine Learning

Transient pressure behavior for unconventional gas wells with finite-conductivity fractures

Gas–liquid flowing process in a horizontal well with premature liquid loading

This paper summarizes important findings from the ongoing National Institute for Occupational Safety and Health (NIOSH) gas well stability research. Over the past seven years, field instrumentation results from NIOSH case studies and active mine-by case studies indicate that, under shallower covers, the measured horizontal displacements within the longwall abutment pillar are one order of magnitude higher than those measured under deep cover. Longwall-induced horizontal displacements occur along weak-to-strong rock interfaces; the sharper the bending stiffness contrast across the interfaces, the larger the longwall-induced horizontal displacements. Longwall-induced vertical compressions under shallower covers are, on the other hand, one order of magnitude lower than those under deep covers. Subsurface strata dip may magnify or reduce longwall-induced horizontal displacements. Uncemented production casings serve to uncouple longwall-induced deformations and stresses from the production casing. A case study is presented to illustrate the importance of leaving the production casing uncemented. INTRODUCTION Since 2003, over 1,800 unconventional shale gas wells have been drilled through active and future Pittsburgh Seam coal reserves in Pennsylvania, West Virginia, and Ohio. These unconventional gas wells, whether tapped into the Marcellus or Utica formations, contain very high gas pressure and volume. Strata deformations associated with underground longwall coal mining could induce stresses and deformations in the shale gas well casings, which in certain situations could compromise the mechanical integrity of the production, intermediate, and coal protection casings. Damaged well casings could potentially introduce high-pressure, high-volume explosive gas into underground mine workings to jeopardize underground miners’ safety and health. To provide critical scientific data to the stakeholders, which includes the Mine Safety and Health Administration (MSHA), the Pennsylvania Department of Environmental Protection (PADEP), the West Virginia Department of Mine Safety (WVDMS), the Ohio Department of Natural Resources (OHDNR), coal operators, and gas operators, NIOSH initiated a research program in 2016 to evaluate the effects of longwall-induced deformations on shale gas well casing stability under deep as well as shallow covers. The effects of longwall-induced subsurface deformations on shale gas well casing stability under deep cover, under medium cover, and under shallow cover were published previously (Su et al., 2018a and 2018b; Su et al., 2019a and 2019b; Su et al., 2020; Zhang et al., 2020; Su and Zhang, 2021; Su et al., 2021). This paper focuses on a case study that illustrates the importance of leaving the production casing uncemented.

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 149477, ’Investigation of Liquid Loading in Tight Horizontal Gas Wells With a Transient-Multiphase-Flow Simulator,’ by Donald F.B. Jackson, SPE, SPT Group, and Claudio J.J. Virues, SPE, and David Sask, SPE, Encana, prepared for the 2011 Canadian Unconventional Resources Conference, Calgary, 15-17 November. The paper has not been peer reviewed. Liquid loading occurs in gas wells when production declines to a rate that is insufficient to lift the associated liquids to the surface. Liquid holdup in the horizontal section may impair production before liquid loading in the production tubing becomes evident. Holdup in the horizontal section can lead to slug flow at the tubing and to early onset of liquid loading in the tubing. The results from a transient-multiphase-flow model were found to be consistent with data acquired from video logging. Sensitivity analyses were performed with several normalized trajectories. Introduction Technology applied in conventional reservoirs in offshore horizontal wells can be applied successfully in onshore horizontal wells in unconventional reservoirs. The Jean Marie formation is an Upper Devonian carbonate platform between two thick shale layers in the Greater Sierra area, approximately 90 km east of Fort Nelson, British Columbia, Canada. The formation has low porosity (averaging 6%), low water saturation (averaging 20%), and low permeability (less than 1 md to air). Formation depth ranges from 600 to 1500 m subsea—1000- to 1900-m true vertical depth. The formation is entirely gas saturated with a dry sweet gas (95% methane) and is variably underpressured, with initial reservoir pressures of 6 to 15 MPa. The horizontal wells are drilled underbalanced to limit formation damage. Fig. 1 shows a typical well completion with 177.8-mm production casing set at the top of the Jean Marie formation. Gas is produced from the openhole portion of the completion. While drilling horizontally through the Jean Marie formation, the well trajectory is steered on the basis of gas-rate-while-drilling (RWD) data. The geologists maneuver up and down in inclination until a good permeability streak is indicated by a spike in flow rate from the RWD data. After reaching target depth, tubing (typically 60.3 mm) is installed and the well is brought on production. Typical gas- production rates for Jean Marie wells decline from an initial rate of 56×103 m3/d to 14×103 m3/d after 12 months and to 10×103 m3/d after 36 months.

ABSTRACT: Shale oil in northeast China is about to enter the stage of large-scale hydraulic fracturing. Cement sheath integrity must be ensured for horizontal shale oil wells. In this paper, the mechanical parameters of cement sheath are measured. A numerical model of casing - cement sheath - formation assembly is established to analyze the stress law of cement sheath. The integrity of the cement sheath is analyzed. The results show that the elastic modulus of cement is 6 GPa and the Poisson’s ratio is 0.17. The compressive strength and tensile strength of cement after cyclic loading are 90MPa and 7.5mpa ~ 11.25mpa respectively. The maximum radial stress of cement sheath increases with the increase of fracturing pressure, the decrease of displacement, and the increase of elastic modulus. The maximum tangential stress of cement sheath increases with the increase of fracturing pressure and elastic modulus of cement. The tensile strength of cement sheath cannot meet hydraulic fracturing requirements. The elastic modulus of cement should be reduced to 4 GPa or the tensile strength should be increased to be higher than 15 MPa. This study would guide the shale oil wells in northeast China. 1. INTRODUCTION As hydraulic fracturing technology matures and international oil prices recover, more and more unconventional oil and gas resources are being developed, such as shale gas, conglomerate reservoirs, and shale oil. In particular, shale oil resources are becoming a new direction of exploration and development of unconventional oil and gas resources in China. Shale oil has been developed scaled in Jimsar block, in Inner Mongolia, and Tianjin district. At the same time, shale oil resources have been successfully explored in northeast China and will soon enter the stage of large-scale development. Based on the development experience of shale gas and other unconventional oil and gas resources over the past few years, casing deformation and sustained casing pressure are the most common problems in horizontal wells during multistage fracturing (Adams, 2017; Atkinson, 2020; Chaojie Zhao, 2020; Xi Yan, 2021.). Well integrity issues have a significant impact on the safety and production of horizontal wells. Fig. 1 shows the casing deformation logging results of Wel-Wei204H39-6 in the Weiyuan block and Well-JHW033 in Jimsar Block, Xinjiang respectively. Logging results showed casing deformation in both wells. One of the wells is a shale gas horizontal well and the other is a shale oil horizontal well. Thus, shale oil wells face the same well integrity issues as shale gas wells.

Abstract: A common industry problem in many flowing gas wells is the gradual build-up of well-bore fluids across the perforations over time. This phenomenon, commonly referred to as liquid loading, is typically seen in many wells that are low-producing, low in pressure, or have long perforation sets. A new gas well de-watering system has been developed to combat this problem, utilizing the reservoir’s energy to help keep it unloaded. This system utilizes a production packer, tail pipe, and carrier subs containing pressure regulating devices in order to trap and use formation gas to keep the well unloaded beneath the packer. This paper will take a closer look into the system through a study of field examples where it was implemented. In the study, one specific well from the US West Rockies Region will be chronicled from the original diagnosis of the liquid loading problem, to the design and installation of the system. Analysis plots are shown to illustrate its success. Additional field examples, within the same and different US fields, will be included to give further illustrations of this de-watering system, while also exemplifying and detailing the system’s limitations in an unsuccessful installation. A comparison analysis will be included and a discussion of lessons learned. The implementation of this system on properly selected wells can significantly impact the performance of low-producing gas wells where liquid loading destroys productivity levels over time. Although it can be run in conjunction with conventional artificial lift, this system introduces a way of utilizing the reservoir’s energy to keep it flowing naturally for a longer period, before artificial lift is necessary. This helps to reduce the overall well costs at a time when the industry is dominated by many tight, unconventional gas wells.

The field-A1 is an offshore gas field located about 56 km from the coast of East Africa with the water depth of 1153 m. The permeability distribution varies across different layers with an overall permeability of 680 m and porosity distribution for the reservoir field-A1 varies 0.21-023. The reservoir thickness also varies up to 50 m thick. This research work identifies parameters that will contribute to the impact of water coning. Simulation sensitivities are run to observe the effect of water coning/cresting in horizontal gas wells and predicting the performance of these wells using Petrel simulator. Results have shown that put horizontal well in East-west will have early water breakthrough and not recommended due to the impact of edge aquifer due to less recovery compared to north-south and original wells orientation (northwest-southeast). The varying height of perforation and standoff as identified is at the standoff between 30-40 m in the field-A2 will delay water coning high recovery with more extended plateau length period. The gas recovery may happen to be low, due to the distribution of permeability layer for the horizontal wells and low productivity index that is the performance of the well. Rate-dependent skin and mechanical skin evolution in time show that increasing non-Darcy /turbulence factor reduces the performance of the well and decreases gas recovery the high drawdown tendency is observed before water breakthrough time however there is early water breakthrough, thus use of deep penetration. Horizontal gas wells have a constant horizontal length for all cases of 300 m increasing tubing head pressure from 40-100 bars result to decrease plateau length period of the gas production, low water production rate, and low gas recovery. Varying the kv/kh ratio from 0.1, 0.6 to 1 shows early water breakthrough by 6 months earlier from the base case with 0.1 hence will not delay water coning. The gas recovery is reduced by 5%. Gas recovery is increased with an increase in gas rates constrain, and early water breakthrough is observed when producing at high rates. Producing at low rates may delay water coning. However, it is not economical since there is less gas recovery and may take a more extended period for production to reach to its total maximum gas production of which is less compared when producing at high gas rates. There is a stronger of the aquifer from the west side, which is predictable to cause water coning than on the east side. This aquifer impacts the gas recovery reduction by 19%, with water coning radial extension of 1.7 km and peak water production rate for 16 years. The aquifer influx rate is seen to be increased by 69% when the aquifer volume is double. Therefore, from the results producing at a high rate that has high recovery before the impact of aquifer or water has occurred to the wells, known as outrunning of the aquifer. To avoid water coning, using advance completion technique such as inflow control devices (ICD), installing a down hole gauge. Also, it is essential not to perforate if well is near to gas water contact the horizontal wells should be located at maximum distance from gas water contact to maximize gas recovery. Not only that but also use of fully open choke allows much water production rate increase, which leads to water coning.

During the completion phase of four unconventional wells in the United Arab Emirates (UAE), a detailed engineering approach enabled overcoming challenges presented by the extreme conditions of pressure, temperature, and sour environment across long horizontal sections to successfully carry out cleanout activities. The methods implemented to address those conditions prioritized personnel safety and asset integrity. The unconventional wells in this campaign were characterized by a reservoir pressure of approximately 13,000 psi and a bottomhole temperature of approximately 325°F. Gas was expected as reservoir fluid. The environment was sour, with 5% mol of H2S and 5% mol of CO2. After fracturing, the shut-in pressure was approximately 8,000 psi. Those conditions triggered a new engineering approach to design a customized coiled tubing (CT) pipe that could reach depths of 20,700 ft and perform efficient cleanouts. Other considerations included the selection of the appropriate pressure control equipment (PCE), downhole tools, and intervention fluids that could withstand the harsh working conditions. The wells were completed with 5 1/2-in. fracturing strings; horizontal sections ranged from 5,000 to 8,200 ft. Each of the 95 fracturing stages was isolated by dissolvable plugs. The CT pipe design considered well trajectories, working pressures, and downhole environment. The highly engineered 22,000 ft, 2 3/8-in. CT string was manufactured with quench and tempered (Q&T) material with yield strength of 110,000 psi. A custom-fit CT string integrity program was implemented to ensure safe intervention in high-pressure sour environment. Pipe life was then monitored in real time using magnetic flux leakage. Downhole tools (CT connector and check valves) and the PCE stack were designed to hold pressures up to 15,000 psi. The PCE configuration was thoroughly reviewed, and since the wellhead stack exhibited a maximum height of approximately 120 ft, a stack stress analysis through finite-element modeling software was conducted to validate structure stability, to confirm forces and bending moments remained within safe working limits, and to determine the optimal setting for guy wires. Job execution highlighted challenges linked to the high-pressure cycling and the need to optimize the number of achievable sweeps in the horizontal section. Well trajectories also proved challenging for the cleanout, with solids accumulation in specific intervals. This operation, the first of its kind in the country for the operator, yielded lessons for design considerations and the execution process and recommendations for CT intervention in similar working environments. It also confirms that 110,000-psi yield strength Q&T CT strings can be safely deployed in a high-pressure sour environment by implementing proper risk mitigation strategies.

We assemble a multiscale physical model of gas production in a mudrock (shale). We then tested our model on 45 horizontal gas wells in the Barnett with 12–15 years on production. When properly used, our model may enable shale companies to gain operational insights into how to complete a particular well in a particular shale. Macrofractures, microfractures, and nanopores form a multiscale system that controls gas flow in mudrocks. Near a horizontal well, hydraulic fracturing creates fractures at many scales and increases permeability of the source rock. We model the physical properties of the fracture network embedded in the Stimulated Reservoir Volume (SRV) with a fractal of dimension D < 2 . This fracture network interacts with the poorly connected nanopores in the organic matrix that are the source of almost all produced gas. In the practically impermeable mudrock, the known volumes of fracturing water and proppant must create an equal volume of fractures at all scales. Therefore, the surface area and the number of macrofractures created after hydrofracturing are constrained by the volume of injected water and proppant. The coupling between the fracture network and the organic matrix controls gas production from a horizontal well. The fracture permeability, k f , and the microscale source term, s, affect this coupling, thus controlling the reservoir pressure decline and mass transfer from the nanopore network to the fractures. Particular values of k f and s are determined by numerically fitting well production data with an optimization algorithm. The relationship between k f and s is somewhat hyperbolic and defines the type of fracture system created after hydrofracturing. The extremes of this relationship create two end-members of the fracture systems. A small value of the ratio k f / s causes faster production decline because of the high microscale source term, s. The effective fracture permeability is lower, but gas flow through the matrix to fractures is efficient, thus nullifying the negative effect of the smaller k f . For the high values of k f / s , production decline is slower. In summary, the fracture network permeability at the macroscale and the microscale source term control production rate of shale wells. The best quality wells have good, but not too good, macroscale connectivity.

Production data analysis of unconventional gas wells: Review of theory and best practices

The production from horizontal tight gas wells is affected negatively by the accumulation of liquids in the bottom of the well (i.e., liquid loading), to the point that additional hydrocarbon production is not possible. In this work we propose an artificial lift method for liquid-loaded horizontal wells, in tight gas shale reservoirs, based on intermittent gas lift principles. An experimental loop was built to test a prototype of the system and explore the operating envelope that determines the optimal liquid removal results. Experimental results are presented in terms of the liquid removal capacity of the device, as a function of the gas injection rate and the Eotvos (Eo) number. Liquid removal values (produced liquid volume / stagnant liquid volume) of up to 75%, and a volumetric efficiency (volume of liquid produced / volume of gas injected) of up to 78% was obtained for the lowest Eotvos number tested (12) at the lowest gas injection rate (0.25 cf/min). Both the liquid removal and the volumetric efficiency behaved inversely proportional to the Eo number and the gas injection flowrate. Reducing the ID of the line, proved to be an efficient approach to reduce the Eotvos number. Using this option resulted in better sweep, but in an increase of the frictional pressure drop. The improved liquid sweep effect of the Taylor bubble at lower Eo is related to a larger radius of the Taylor bubble and a change on the shape of its nose.

A machine learning-based predictive model for real-time monitoring of flowing bottom-hole pressure of gas wells

This research presents the selection of an appropriate decline curve analysis (DCA) methodology according to the transient production performance of a multi-fractured horizontal well in an unconventional gas field by using the cumulative production incline rate (IQp) The IQp introduced in this research is the change of cumulative production per unit time divided by the cumulative production. The IQp was confirmed for use as an indicator that could generalise and quantify a production decline through the analysis of well production data. The IQp values of eight and four DCA methods were applied to the production data generated by a reservoir simulation. The Duong method forecasted the production trends most accurately when the IQp exceeded 0.25%, while the YM-SEPD method was the most preferable for the rates below 0.05%. In addition, the analysis of production data for shale gas wells in Canada and the USA matched the simulation results, confirming that it would be reasonable to use the IQp in order to select a DCA method to forecast the production of unconventional gas wells. [Received: February 23, 2017; Revised: December 7, 2017; Accepted: December 9, 2017]

Length and profile shape of horizontal section of the production well is one of the main issues in the justification of horizontal well completion. Justified choice of horizontal well completion and profile design is based on the main objectives: provide high initial rate, maximize the cumulated gas and condensate production, reduce the risk of well drilling and completion, extend a period with water free production, hence resulted in the maximum NPV. The main factors that influence the choice of horizontal well profile are the geological structure of the productive formation, its reservoir properties, the location of formation fluid contacts, formation anisotropy, the ratio of vertical and horizontal heterogeneity. In this paper we investigate the influence of mentioned geological factors on the choice of horizontal well profile. Various profiles of horizontal wells- directional, horizontal and U-shaped have been considered for gas condensate reservoirs. The analysis was conducted on the basis of hydrodynamic modeling Eclipse 300 using a function of multi-segment well. After choice of the optimal length for the horizontal section of the well, a simulation was performed. Also there was a comparison of the performance for directional and U-shaped horizontal wells with the same length. During comparing the well performance well productivity, cumulative gas and condensate production, inflow profiles, the conditions of liquid removing from well bottom of were evaluated. Sensitivity evaluation of the optimal profile selecting to the reservoir permeability and its anisotropy was performed. It helps to take into account the effect of uncertainty on the performance of the well. Selecting a profile of the horizontal section of the well is one of the main issues in the design and affects not only the final gas and condensate recovery, but also helps to clarify the geological structure formation during logging, and enable the development of all productive layers, reduce the risk of complications during the operation. Structural features of horizontal wells unlike allow to obtain vertical flow rates several times superior performance of vertical wells. And the increase in horizontal wells is provided not by increasing the drawdown, and by increasing the filter surface. Productivity is limited in the vertical wells of the reservoir reveals the thickness, whereas the thickness of a predetermined value for the formation and drawdown -the geometrical parameters of the liner and, consequently, horizontal wells depends on the length of the horizontal wellbore. The horizontal wellbore completion may be regarded as an effective method for production of hydrocarbons, and as a method of stimulation. Engineering and technology horizontal drilling, completion fluid, their performance, conduct work under stimulation to them, economic indicators drilling and operation of horizontal wells devoted several thousand research. At the same time question the justification of the optimal design and the length of the gas and gas condensate wells are virtually unexplored. Studies on this topic have been done by Z.S. Aliyev, V. Sheremet and V.A. Chernykh. Z.S. Aliyev in one of his works says that the only way to study the optimal design of horizontal gas wells drilled in inhomogeneously layered strata, is a numerical solution to this problem through the creation of geological and mathematical models of fragments of such deposits and the joint solution of unsteady, multidimensional, multiphase and multicomponent filtering the horizontal trunk with the equation of motion with a variable flow rate of the mixture along the length of the barrel. In this paper we provide a rationale for completing horizontal wells for specific geological conditions of the N-th gas condensate field located in the east of the autonomous area.

Owing to low productivity of vertical wells in shale gas formations, operators have started to drill horizontal wells in these ultra-tight gas formations. Wells that are drilled in shale formations have undergone massive hydraulic fracturing treatments to improve the productivity. Since the introduction of horizontal drilling in shale formations, wells have been hydraulically fractured at several stages. Each stage is located a few hundred feet away from the other stages. Multi-Stage fracturing of horizontal drilling in shale gas wells increases the production significantly. Integration of detailed fracture network mapping in numerical simulation of these reservoirs is impractical because of high resolution time-space seismic data required to map the fracture surfaces, which in most wells are not acquired because of economic considerations. Multi-million cell numerical models are required for each individual well due to massive refining of gridblocks around the fractures. Conditioning the refined reservoir models to performance data adds to the complexity of the problem, since any adjustments made to the fracture properties can change the gridding of the model. Hence, automatic history matching tools are not well suited for application in grid-refined, detailed geological models representing shale gas reservoirs and wells. In this study, we propose a new multi-stage compartmentalized numerical modeling technique for shale gas reservoirs, which is an extension to dual porosity modeling. The methodology is simplistic, is not built using detailed high resolution fracture maps, and requires less CPU time. Ensemble Kalman Filter (EnKF), a minimum mean square error estimation tool, is used for estimating the reservoir properties. Combined EnKF/compartmentalized modeling technique is implemented in this paper to automatically estimate the fracture properties of the fracturing stages of a horizontal well. The algorithm only requires well’s performance data, such as gas production rates, flow back volumes, bottom-hole pressures, and tracer concentrations. Numerical models that are conditioned to observations are shown to accurately estimate the production rates and are useful for reserves booking and field development.