Conventional Gas Wells Research Articles

Analysis of Downhole Throttling Technology of Gas Wells

Downhole throttling technology relies on downhole throttling to achieve the purpose of wellbore throttling and pressure reduction. Compared with surface throttling, downhole throttling can not only use ground temperature heating, effectively prevent the shaft and wellhead from freezing, but also reduce the wellhead pressure and save the cost of surface pipeline. It solves many technical problems in the process of gas well production, and plays a key role in energy saving and safety production of gas well. At present, a set of mature calculation methods have been developed for the production calculation of conventional gas Wells. However, for throttle gas Wells, due to the influence of fluid accumulation, the accuracy of conventional calculation method is low, which leads to a large error in the selection of throttle size. Therefore, it is of great practical significance to study the downhole throttling technology and optimize the parameters of downhole throttling.

A Dynamic Plunger Lift Model for Shale Gas Wells

At present, the optimization of the plunger mechanism is shale gas wells is mostly based on empirical methods, which lack a relevant rationale and often are not able to deal with the quick variations experienced by the production parameters of shale gas wells in comparison to conventional gas wells. In order to mitigate this issue, in the present work, a model is proposed to loosely couple the dynamics of gas inflow into shale gas wells with the dynamics of the liquid inflow. Starting from the flow law that accounts for the four stages of movement of the plunger, a dynamic model of the plunger lift based on the real wellbore trajectory is introduced. The model is then tested against 5 example wells, and it is shown that the accuracy level is higher than 90%. The well ‘switch’, optimized on the basis of simulations based on such a model, is tested through on-site experiments. It is shown that, compared with the original switch configuration, the average production of the sample well can be increased by about 15%.

Cost analysis of wastewater production from conventional and unconventional oil and gas wells

Production of high volumes of flowback and produced water (FPW) from hydraulic fracturing (HF) is among the environmental concerns associated with hydrocarbon recovery from unconventional low-permeability formations. FPW management costs are a key factor for oil and gas companies in deciding the fate of FPW (treatment, disposal, recycling, and reuse). In this study, a comprehensive library of more than 20,000 oil and gas wells in the Montney Formation, Canada, is created to compare the FPW management costs from conventional and hydraulically fractured wells. The results indicate that for oil wells, both conventional and HF wells have similar volumetric oil–water ratios during the first two years of production. Since HF wells in the study region produce higher volumes of oil, on average, than conventional wells, the gross revenue from a typical HF oil well is higher than a typical conventional oil well. However, over the course of two years of production, conventional gas wells have higher volumetric gas–water ratios than HF gas wells. Estimation of the gross revenue for gas wells is sensitive to the average natural gas price and FPW management costs as HF wells typically generate more natural gas and FPW than conventional wells. Due to the fluctuating nature of oil and gas prices, we have created master curves for revenue (i.e., produced hydrocarbon value) and FPW management costs. The master curves cover oil and gas price ranges of $10–100/bbl and $0.5–5/MMBtu, respectively. Furthermore, since the FPW management costs may vary depending on the implemented technology or local labor costs, the master curves encompass a FPW management cost range of $5–100/m3. The provided master curves introduce a basis for the rapid analysis of FPW management costs of oil and gas wells, and can be incorporated with other well operational costs (such as drilling and completions, water withdraw permit, and well maintenance) for detailed evaluation of the profitability of hydrocarbon recovery processes.

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

Prediction of the flowing bottom hole pressure (FBHP) of gas–water two-phase flows is of great importance in optimising the production of gas and reducing down-time in unconventional gas wells. Unlike the case for conventional gas wells, prediction of FBHP for unconventional gas wells, particularly coal seam gas (CSG) wells, has not been studied.Monitoring of FBHP typically is done using a downhole pressure sensor placed close to the bottom of the well. Replacing a failed pressure sensor or recalibration of a pressure gauge, which is required frequently throughout the life of a well for reliable measurement of FBHP, requires interruption of the gas production at a high cost. A low-cost and reliable model for continuous prediction of FBHP, would enable smooth operation of CSG wells in the event a pressure gauge fails, without interrupting the well production.This work presents predictive models for real-time and reliable prediction of FBHP using surface and subsurface data, acquired from 91 CSG wells in Australia over 5–19 month production periods. Two sets of models are developed; one for specific wells using data from that individual well and another one for a group of wells. Three different modelling approaches, multiple linear regression, linear mixed-effects and gradient boosting regression tree (XGBoost) are implemented. The XGBoost modelling outcomes show promising results with the best mean absolute percentage error (MAPE) of 10% and 11.7% for specific well models and multiple well models, respectively.

Spatiotemporal wave propagation of the shale oil and gas development in the Marcellus Shale in the past one century and a half

ABSTRACT Dense shale oil and gas extraction activities have a long history in the Marcellus Shale and the investigation of their evolution draws increasing interest. The spatiotemporal analysis of these shale oil and gas extraction activities is essential to understand their evolution in space-time, and important for the estimation of their historical impacts on local environments and communities. These shale oil and gas extraction activities formed numerous scattered hot spots, and it demands tremendous efforts to trace them over time. This particular issue then challenges the conventional spatiotemporal analysis approaches which are effective for single or limited spatiotemporal objects. This study models the spatiotemporal developments of the shale oil and gas extraction activities as wave propagation. By using the wave representation, the complicated transmission of these shale oil and gas extraction activities is automatically traced within a sub-space-time as free propagation. To implement the proposed wave model, density surfaces of active wells from 1868 to 2018 were estimated annually. A 15-year focal statistic filter was applied to the density curve at each location to identify temporal objects. The waves were formed from temporal objects using a spatiotemporal expansion algorithm while maximally allowing 1 gap year. Finally, comprehensive attributes were derived for each wave. The results indicate that chaotic and fragmentary waves propagated at the western and northern edges of the Marcellus Shale. In contrast, large and simple wave propagation occurred in the middle of the Marcellus Shale. The propagation of large waves has a southward general trend, the trend follows the Appalachian region’s mountainous topography. Different types of drilling activities show diversified wave propagation patterns and the conventional gas wells formed the most chaotic wave propagation. The wave representation is successfully applied to the evolution of the shale oil and gas extraction activities, and this study also develops a comprehensive set of attributes to depict the wave. The scattered hot spots of dense shale oil and gas extraction activities are automatically assembled in waves. These concrete and detailed attributes of the waves are effective in summarizing the general spatiotemporal evolution pattern of chaotic and fragmentary spatiotemporal objects, e.g., the dense shale oil and gas extraction activities in this case. The developed method is also transferable and applicable to the evolution of other geographic phenomena, which may comprise of either limited or numerous spatiotemporal objects.

Review of metering and gas measurements in high-volume shale gas wells

Coriolis, turbine, V-cone, and orifice meters have been used in measurement of gas production in shale wells. Flange-tapped concentric orifice meters are commonly used in measurement of shale gas production volumes due to their low cost, accuracy, and ease of maintenance compared to other types of meters. However, shale gas wells are producing at high flow rates, high pressure, and possibly gas compositions change, which might affect volumetric measurement accuracy that was developed for conventional gas wells. Thus, it is critical to investigate the metering and measurements technologies that are being applied in shale gas wells to further understand and improve the accuracy of gas volumetric measurements. This paper provides a comprehensive review and analysis of background information, design, measurement, and uncertainties associated with Coriolis meters, turbine meters, V-cone meters, and orifice meters. We also discussed the lessons learned through our field experiences in computing gas volumes using SCADA information in shale gas and conventional gas production.

The current perspective of the PA 1957 gas well pillar study and its implications for longwall gas well pillars

Many states rely upon the Pennsylvania 1957 Gas Well Pillar Study to evaluate the coal barrier surrounding gas wells. The study included 77 gas well failure cases that occurred in the Pittsburgh and Freeport coal seams over a 25-year span. At the time, coal was mined using the room-and-pillar mining method with full or partial pillar recovery, and square or rectangle pillars surrounding the gas wells were left to protect the wells. The study provided guidelines for pillar sizes under different overburden depths up to 213 m (700 ft). The 1957 study has also been used to determine gas well pillar sizes in longwall mines since longwall mining began in the 1970 s. The original study was developed for room-and-pillar mining and could be applied to gas wells in longwall chain pillars under shallow cover. However, under deep cover, severe deformations in gas wells have occurred in longwall chain pillars. Presently, with a better understanding of coal pillar mechanics, new insight into subsidence movements induced by retreat mining, and advances in numerical modeling, it has become both critically important and feasible to evaluate the adequacy of the 1957 study for longwall gas well pillars. In this paper, the data from the 1957 study is analyzed from a new perspective by considering various factors, including overburden depth, failure location, failure time, pillar safety factor (SF), and floor pressure. The pillar SF and floor pressure are calculated by considering abutment pressure induced by full pillar recovery. A statistical analysis is performed to find correlations between various factors and helps identify the most significant factors for the stability of gas wells influenced by retreat mining. Through analyzing the data from the 1957 study, the guidelines for gas well pillars in the 1957 study are evaluated for their adequacy for room-and-pillar mining and their applicability to longwall mining. Numerical modeling is used to model the stability of gas wells by quantifying the mining-induced stresses in gas well casings. Results of this study indicate that the guidelines in the 1957 study may be appropriate for pillars protecting conventional gas wells in both room-and-pillar mining and longwall mining under overburden depths up to 213 m (700 ft), but may not be sufficient for protective pillars under deep cover. The current evaluation of the 1957 study provides not only insights about potential gas well failures caused by retreat mining but also implications for what critical considerations should be taken into account to protect gas wells in longwall mining.

Innovative Energy Solutions-Shale Gas In India

Shale gas is a major domestic option for natural gas of a country where conventional gas reserves had been used up. It is entrapped in between shale formations, having low permeability that makes its commercial production extremely difficult. Major constituent is methane which is utilized for synthesizing Ammonia and Methanol. Natural Gas Liquids (NGLs) constituents such as Ethane, Propane and Butane are utilized for Ethylene synthesis. Ethylene synthesized by Shale gas is preferred over that of manufactured by Naphtha.CO2, N2 and H2S are small fraction non-hydrocarbon constituents. Production of shale gas had lowered the dependency of nations to Middle-east for their energy needs but shale production comes at a high cost of environment degradation. About 3% of extracted gas is being released in the atmosphere, fracturing of underlying rocks can induce small earthquakes and quick exhaustion of shale wells in comparison to conventional gas wells are major disadvantages. Fracking fluid being used for Hydraulic Fracking consists of large quantities of water, sand and chemicals. After the process, vital fractions of it left underground can possibly pollute underground water sources. A long term study of the process is still desired in order to reveal exact intricacies of Environment Contamination. A Shaft is drilled into the ground up to the depth of gas bearing layer Fracking fluid is then pumped using high performance pumps. Fluid mixture penetrates into the rock layer and produces innumerable tiny cracks. Water acts as solvent, sand holds up the opening, Chemicals condense water, kill off bacteria and dissolve minerals. Production of shale gas then begins. After the reserve is exhausted, some amount of fracking fluid is pumped in again and then the drill hole is sealed. A general observed fact is that in every hydrocarbon producing nation there is an equal likelihood regarding the presence of shales holding hydrocarbons. As published in the report of EIA, June 2013 amount of shale gas resources in India is 584 tcf and the technically recoverable amount is about 96 tcf (Cambay, Krishna-Godavari, Cauvery, Damodar Valley, Upper Assam, Pranhita-Godawari, Rajasthan and Vindhyan basins). Vital task before shale gas production includes the ultimate analysis of geological properties of shales in order to produce gas/oil from them. In this regard, government with the support of many private agencies had drilled several thousand wells (mainly in Cambay, KG and Cauvery basins).These wells had provided extensive data on extent, depth and nature of shale formations in sedimentary basins. However, a lot of work is still left to actually start commercial production of shale gas on Indian soil.

Design of electrical submersible pumps in methane hydrate production wells: A case study in Nankai trough methane hydrates

Gas hydrate industry aims to conduct long-term gas hydrate production trials after gaining the experiences in short-term gas hydrate production trials. Electrical submersible pumps (ESP) were mostly chosen in gas hydrate production trials to depressurize gas hydrate reservoirs. However, there is a knowledge gap about the usage and design of ESP systems in gas hydrate wells. Therefore, in this study, it is aimed to design ESP systems in methane hydrate production well in the conditions of Nankai Trough (Japan) methane hydrate reservoirs. For this purpose, a set of python codes was written to design ESP in the case study gas hydrate well and also HEP simulator was used to predict gas hydrate formation risks along the wellbore during gas production from methane hydrates via ESP production string. It was shown that high variances in water production rates (50–794 m3/day) affect the pump performance negatively, especially in the outside of suggested pump working flow rates. Moreover, pump efficiencies decrease from 70 s% to 20 s% in the outside of pump working flow rates due to huge variances in water flow rates during production. Different than conventional gas wells, the temperature rise generated by the motor is important to avoid any gas hydrate formation in gas hydrate well, which was affected by the operating frequency. Above 40 Hz of operating frequency, well temperature increases (nearly 0.65–1.75°C) by the motor with increasing frequency, which is good for the prohibition of gas hydrate formation in the well. In terms of pump power requirements, there is no difference of producing water at sea surface and releasing produced water to the seafloor. According to the methane hydrate equilibrium predictions in the wellbore during production with ESP, methane hydrate is not like to form in the design conditions. However, with ESP malfunction, methane hydrate might form inside the well due to increasing wellbore pressure and decreasing well temperature.

Influence of longwall mining on the stability of gas wells in chain pillars

Longwall mining has a significant influence on gas wells located within longwall chain pillars. Subsurface subsidence and abutment pressure induced by longwall mining can cause excessive stresses and deformations in gas well casings. If the gas well casings are compromised or ruptured, natural gas could migrate into the mine workings, potentially causing a fire or explosion. By the current safety regulations, the gas wells in the chain pillars have to be either plugged or protected by adequate coal pillars. The current regulations for gas well pillar design are based on the 1957 Pennsylvania gas well pillar study. The study provided guidelines for gas well pillars by considering their support area and overburden depth as well as the location of the gas wells within the pillars. As the guidelines were developed for room-and-pillar mining under shallow cover, they are no longer applicable to modern longwall coal mining, particularly, under deep cover. Gas well casing of failures have occurred even though the chain pillars for the gas wells met the requirements by the 1957 study. This study, conducted by the National Institute for Occupational Safety and Health (NIOSH), presents seven cases of conventional gas wells penetrating through longwall chain pillars in the Pittsburgh Coal Seam. The study results indicate that overburden depth and pillar size are not the only determining factors for gas well stability. The other important factors include subsurface ground movement, overburden geology, weak floor, as well as the type of the construction of gas wells. Numerical modeling was used to model abutment pressure, subsurface deformations, and the response of gas well casings. The study demonstrated that numerical models are able to predict with reasonable accuracy the subsurface deformations in the overburden above, within, and below the chain pillars, and the potential location and modes of gas well failures, thereby providing a more quantifiable approach to assess the stability of the gas wells in longwall chain pillars.

Research of Dynamic Reserves Estimation Methods for Complex Gas Wells in Low Permeability and Tight Gas Reservoir

As material basis of compiling and adjusting developing scheme, dynamic reserves are crucial for predicting well spacing density and stable production potential. Currently, for conventional gas wells with good physical properties and abundant pressure test data, the main evaluation methods of dynamic reserves are ranging from material balance equation to flowing material balance. However, complex gas wells in Ordos Basin such as type of inadequate pressure test data in low permeability reservoir, water production, downhole throttling in tight gas reservoir, these three types of wells cannot be easily applied to the current evaluation methods. Therefore, this paper presents rapid methods for estimating dynamic reserves in complicated situations which are based on analysis of gas wells percolation and production. The key points of new methods are evaluation of the formation pressure without shutting well, visual pressure drop and water influx, pseudo-pressure regularization rate under superposition time function respectively. Finally, with applying methods to track and evaluate the dynamic reserves of M gas field in Ordos Basin, results show that approaches are accurate and evaluation periods are greatly shortened. Besides, the procedures are simple which can be implemented in desktop application or spreadsheet with minimal computational effort.The new methods provide a direct reference for the deployment of gas infilling wells and gas wells refracturing, and further improve the utilization level of reserves.

Origin of Flowback and Produced Waters from Sichuan Basin, China.

Shale gas extraction through hydraulic fracturing and horizontal drilling is increasing in China, particularly in Sichuan Basin. Production of unconventional shale gas with minimal environmental effects requires adequate management of wastewater from flowback and produced water (FP water) that is coextracted with natural gas. Here we present, for the first time, inorganic chemistry and multiple isotope (oxygen, hydrogen, boron, strontium, radium) data for FP water from 13 shale gas wells from theLower Silurian Longmaxi Formation in the Weiyuan gas field, as well as produced waters from 35 conventional gas wells from underlying (Sinian, Cambrian) and overlying (Permian, Triassic) formations in Sichuan Basin. The chemical and isotope data indicate that the formation waters in Sichuan Basin originated from relics of different stages of evaporated seawater modified by water-rock interactions. The FP water from shale gas wells derives from blending of injected hydraulic fracturing water and entrapped saline (Cl ∼ 50,000 mg/L) formation water. Variations in the chemistry, δ18O, δ11B, and 87Sr/86Sr of FP water over time indicate that the mixing between the two sources varies with time, with a contribution of 75% (first 6 months) to 20% (>year) of the injected hydraulic fracturing water in the blend that compose the FP water. Mass-balance calculation suggests that the returned hydraulic fracturing water consisted of 28-49% of the volume of the injected hydraulic fracturing water, about a year after the initial hydraulic fracturing. We show differential mobilization of Na, B, Sr, and Li from the shale rocks during early stages of operation, which resulted in higher Na/Cl, B/Cl, Li/Cl, and 87Sr/86Sr and lower δ11B of the FP water during early stages of FP water formation relative to the original saline formation water recorded in late stages FP water. This study provides a geochemical framework for characterization of formation waters from different geological strata, and thus the ability to distinguish between different sources of oil and gas wastewater in Sichuan Basin.

Drainage gas recovery technology for high-sulfur gas wells by a canned ESP system

In order to apply the electric submersible pump (ESP) based drainage gas recovery technology commonly used in conventional gas wells to high-sulfur gas wells, and meet the requirements of casing protection in high-sulfur gas wells, we conducted a series of technical researches on casing protection, gas interference and vibration of deep-well ESP set in terms of a completion string design and support tools based on the completion modes of high-sulfur gas wells and the technical characteristics of ESP drainage gas recovery technologies. Simultaneously, drainage gas recovery technology was designed for Well L2. The research and application results show: firstly, the completion string system of high-sulfur gas wells composed of a canned ESP system and an anchor intubation packer can realize the normal operation of ESP and meet the requirements of casing protection; secondly, multiphase pump and bleeder line can be used to solve the problem of gas interference, the automatic reverse valve can be used to reduce the effect of ESP complex flow path on the flowing of the gas well, and the anchor intubation packer can be used to reduce the string vibration; thirdly, the canned ESP system designed in this paper is applicable to Ø244.5 mm and Ø177.8 mm casings, specifically, the ESP corresponding to Ø244.5 mm casing has the maximum flow rate of 900 m3/d and the maximum lift height of 4500 m, and that corresponding to Ø177.8 mm casing has the maximum flow rate of 300 m3/d and the maximum lift height of 3000 m. It is concluded that this research result provides a technical support for the implementation of ESP based drainage gas recovery technology in high-sulfur gas wells.

Big Groundwater Data Sets Reveal Possible Rare Contamination Amid Otherwise Improved Water Quality for Some Analytes in a Region of Marcellus Shale Development.

Eleven thousand groundwater samples collected in the 2010s in an area of Marcellus shale-gas development are analyzed to assess spatial and temporal patterns of water quality. Using a new data mining technique, we confirm previous observations that methane concentrations in groundwater tend to be naturally elevated in valleys and near faults, but we also show that methane is also more concentrated near an anticline. Data mining also highlights waters with elevated methane that are not otherwise explained by geologic features. These slightly elevated concentrations occur near 7 out of the 1,385 shale-gas wells and near some conventional gas wells in the study area. For ten analytes for which uncensored data are abundant in this 3,000 km2 rural region, concentrations are unchanged or improved as compared to samples analyzed prior to 1990. Specifically, TDS, Fe, Mn, sulfate, and pH show small but statistically significant improvement, and As, Pb, Ba, Cl, and Na show no change. Evidence from this rural area could document improved groundwater quality caused by decreased acid rain (pH, sulfate) since the imposition of the Clean Air Act or decreased steel production (Fe, Mn). Such improvements have not been reported in groundwater in more developed areas of the U.S.

Shallow gas development and grassland songbirds: The importance of perches

ABSTRACTGrassland bird species have declined more than birds of any other region in North America and industrial development may exert further pressure on these species. We evaluated effects of conventional natural gas infrastructure on the relative abundances of grassland songbirds in southeastern Alberta, Canada at sites with shallow gas well pad densities ranging from 0 to 16 pads/258 ha (0–24 well heads/258 ha). Conventional gas wells have a relatively small footprint and minimal associated noise and maintenance activities, allowing us to focus on effects of the infrastructure itself and vegetation surrounding wells. We conducted fixed‐radius point counts and vegetation sampling at 34 sites in 2010 and 40 sites in 2011. We used generalized linear mixed models and information theory to evaluate effects of infrastructure on birds. Relative abundances of vesper sparrow (Pooecetes gramineus) and western meadowlark (Sturnella neglecta) increased near gas wells, whereas abundance of the threatened Sprague's pipit (Anthus spragueii) declined. Vegetation near infrastructure was shorter and sparser than locations farther from wells, but discrepancies with avian habitat preferences suggest that, in contrast to conclusions of previous studies, vegetation structure could not explain responses to infrastructure by birds. Instead, gas wells may have acted as artificial shrubs because they attracted species that use vegetation for perching but were avoided by species that avoid shrubs. Our results suggest that observed effects were a direct result of the presence of wells and associated fencing, and thus risk mitigation should focus on reducing the extent of aboveground infrastructure. © 2017 The Wildlife Society.

Temperature‐dependent Li isotope ratios in Appalachian Plateau and Gulf Coast Sedimentary Basin saline water

AbstractLithium (Li) concentrations of produced water from unconventional (horizontally drilled and hydraulically fractured shale) and conventional gas wells in Devonian reservoirs in the Appalachian Plateau region of western Pennsylvania range from 0.6 to 17 mmol kg−1, and Li isotope ratios, expressed as in δ7Li, range from +8.2 to +15‰. Li concentrations are as high as 40 mmol kg−1 in produced waters from Plio‐Pleistocene through Jurassic‐aged reservoirs in the Gulf Coast Sedimentary Basin analyzed for this study, and δ7Li values range from about +4.2 to +16.6‰. Because of charge‐balance constraints and rock buffering, Li concentrations in saline waters from sedimentary basins throughout the world (including this study) are generally positively correlated with chloride (Cl), the dominant anion in these fluids. Li concentrations also vary with depth, although the extent of depth dependence differs among sedimentary basins. In general, Li concentrations are higher than expected from seawater or evaporation of seawater and therefore require water–mineral reactions that remove lithium from the minerals. Li isotope ratios in these produced waters vary inversely with temperature. However, calculations of temperature‐dependent fractionation of δ7Li between average shale δ7Li (−0.7‰) and water result in δ7Liwater that is more positive than that of most produced waters. This suggests that aqueous δ7Li may reflect transport of water from depth and/or reaction with rocks having δ7Li lighter than average shale.

Assessing dissolved methane patterns in central New York groundwater

Abstract Study region Groundwater in Chenango County (central New York State, USA), which is underlain by Devonian sedimentary bedrock. This region has conventional natural gas wells and is under consideration for future shale gas development using high-volume hydraulic fracturing. Study focus The study examines current patterns of dissolved methane in groundwater, based on 113 samples from homeowner wells in the spring of 2012. Samples were analyzed for methane and other water quality parameters, and each well characterized by its landscape position and geology. Statistical testing and regression modeling was used to identify the primary environmental drivers of observed methane patterns. New hydrological insights for this region There was no significant difference between methane concentrations in valleys versus upslope locations, in water wells less than or greater than 1 km from a conventional gas well, and across different geohydrologic units. Methane concentrations were significantly higher in groundwater dominated by sodium chloride or sodium bicarbonate compared with groundwater dominated by calcium bicarbonate, indicating bedrock interactions and lengthy residence times as controls. A multivariate regression model of dissolved methane using only three variables (sodium, hardness, and barium) explained 77% of methane variability, further emphasizing the dominance of geochemistry and hydrogeology as controls on baseline methane patterns.

Study of Fluid Phase Behavior and Pressure Calculation Methods of a Condensate Gas Well

To date, researchers are still using the method used for conventional gas wells to calculate the wellbore flowing pressure of condensate gas wells, while the calculating accuracy cannot meet the demands of performance analysis and production management. From the analysis of wellbore phase behavior transition in the production process, combined with wellbore temperature distribution change, the pressure calculation model is established based on gas-liquid equilibrium calculation and solved with the four-point implicit difference scheme. The calculated result agrees well with the actual situation and can solve the problem that the pressure gauge could neither be put in the middle part of layer nor operate normally, in order to save a great deal of manpower and material resources.

Geochemical evaluation of flowback brine from Marcellus gas wells in Pennsylvania, USA

Large quantities of highly saline brine flow from gas wells in the Marcellus Formation after hydraulic stimulation (“fracking”). This study assesses the composition of these flowback waters from the Marcellus shale in Pennsylvania, USA. Concentrations of most inorganic components of flowback water (Cl, Br, Na, K, Ca, Mg, Sr, Ba, Ra, Fe, Mn, total dissolved solids, and others) increase with time from a well after hydraulic stimulation. Based on results in several datasets reported here, the greatest concentration of Cl− in flowback water is 151,000 mg/L. For total Ra (combined 226Ra and 228Ra) in flowback, the highest level reported is 6540 pCi/L. Flowback waters from hydraulic fracturing of Marcellus wells resemble brines produced from conventional gas wells that tap into other Paleozoic formations in the region. The Br/Cl ratio and other parameters indicate that both types of brine formed by the evaporation of seawater followed by dolomitization, sulfate reduction and subsurface mixing with seawater and/or freshwater. Trends and relationships in brine composition indicate that (1) increased salt concentration in flowback is not mainly caused by dissolution of salt or other minerals in rock units, (2) the flowback waters represent a mixture of injection waters with highly concentrated in situ brines similar to those in the other formations, and (3) these waters contain concentrations of Ra and Ba that are commonly hundreds of times the US drinking water standards.