Developments in Pennsylvanian in 1949

The sharp decline in gas well drilling which began in 1950 continued through 1951. Two discoveries near the close of the year give promise of more successful gas development during the coming year. Total wells drilled amounted to 1,061 of which 626 were producers and 435 were dry. No new oil pools of note were discovered. The lack of significant gas discoveries during 1951 resulted in a continued decline in the total wells drilled in this category. Two discoveries near the close of the year, one in the city of Wooster, Wayne County, and the other in Belpre and Watertown townships, Washington County, give promise of more successful gas operations during the coming year. Ten hundred and sixty-one wells were reported completed in 45 counties during 1951. Discoveries amounted to 142,611,000 cubic feet of gas and 9,956 barrels of oil initial per day. These were derived from 240 gas wells drilled in 34 counties, 315 oil wells in 30 counties, and 71 combination wells in 15 counties. Forty-one per cent, or 435 of all wells drilled, resulted in dry holes. Total footage drilled amounted to 2,083,838 feet. Of thi , 552,319 feet discovered gas, 500,915 feet found oil, 174,271 feet produced both oil and gas, and 856,323 feet proved unsuccessful. The average depth of all wells drilled was 1,964 feet. Thirty-seven per cent of all wells drilled were seeking Berea sand production. Thirty-seven per cent also tested the Clinton. Sixty per cent of all gas and 69 per cent of all oil discovered during the year were found in the Clinton sand. The largest gas well reported during the year was completed by B. H. Putnam on the J. S. Lamp farm, Lot 66, Belpre Township, Washington County. The Oriskany sand was found from 4,080 to 4,116 feet and produced 750 MCF natural. After a 90-quart nitroglycerine shot it increased to 5,890 MCF. Initial rock pressure was 1,675 psi. Sheffield Oil and Gas Company discovered the largest oil well of the year on the Lee Dugan farm, Section 18, Jackson Township, Knox County. The Clinton sand was found from 2,995 to 3,046 and yielded 55 barrels natural. The first 24 hours after a 20-quart shot, it produced 300 barrels. The most active counties were Ashland with 145 wells completed, Perry and Washington with 88 each, Coschocton 79, Noble 65, Holmes 58, Monroe and Knox 52 each, and Medina 51. The four leading counties in gas discoveries were: Perry, 16,135,000 cubic End_Page 1058------------------------------ Fig. 1. Areas of drilling activity during 1951. End_Page 1059------------------------------ feet per day initial; Medina, 13,681,000; Holmes, 13,329,000; and Coshocton, 11,980,000. Coshocton County led in new oil discovered with 3,290 barrels per day initial. Following Coshocton were Ashland with 1,165 barrels, Licking with 1,066, and Knox with 1,003 barrels. Exploratory drilling results during the year were discouraging. Of the 32 wells in this category 26 were dry holes. Approximately 1,900 acres were proved as the result of 3 new gas-pool discoveries. These are as follows. 1. Northwestern Jefferson Township, Tuscarawas County, 5 gas wells and 1 dry hole in the Berea sand proved 400 acres. Average initial open flow was 820 MCF, rock pressure 385 psi, and depth 955 feet. The discovery well was the Stone Creek Brick Company's Marsh No. 1 in Lot 30. 2. A Newburg sand pool was discovered by the Ohio Fuel Gas Company's Spreng Table I. NEW OIL AND GAS PRODUCTION DISCOVERED DURING 1951, BY COUNTIES End_Page 1060------------------------------ No. 1, Section 29, Knox Township, Holmes County. Four productive wells averaging 1,024 MCF, 776 psi, and 2,417 feet, proved 800 acres. 3. Six gas wells in the Clinton sand in southwestern Worthington Township, Richland County, averaged 1,862 MCF, 914 psi, and 2,458 feet. Approximately 700 acres were proved. The discovery well was the Fierbaugh and Lyons' Morgan No. 1 located in Section 30. 4. The possibility of a major new field may result from two discovery wells drilled in Washington County. These wells are located in Belpre and Watertown townships, nearly 20 miles apart. No estimate of the importance of these discoveries can be made until further development is completed. Approximately 9,500 acres were proved as the result of extensions to older gas pools. The more important were the following. 1.--Southeastern Olive Township, Meigs County, 13 Berea sand wells averaged 454 MCF, 690 psi, and 2,024 feet. Sixteen hundred acres were added. 2.--Northwestern Summit Township, Monroe County, 6 Berea wells averaged 45 MCF, 594 psi, and 1,880 feet. About 500 acres were proved. 3.--Seven Clinton sand gas wells and 1 dry hole added 600 acres to an old pool in northeast Granger Township, southwest and central Hickley Township, Medina County. The averages were 538 MCF, 670 psi, and 3,485 feet. 4.--In couth-central Hopewell Township, Perry County, 4 Clinton sand wells added 500 acres to an existing. The averages were 425 MCF, 636 psi, and 2,980 feet. 5.--Four gas wells, 3 oil wells, and 4 dry holes drilled in northwestern Canaan Township, Wayne County, added 600 acres to an old pool. Production was found in both the Newburg and Clinton sands at an average depth of 3,070 feet. No new oil pools of note were discovered during the year. The principal areas of extensions are as follows. 1.--Forty-one oil wells completed in the Clinton sand in New Castle Township, End_Page 1061------------------------------ Coshocton County, averaged 64 barrels initial. Approximately 500 acres were developed and 200 acres proved. The largest well was the Preston Oil's Daliere No. 4 which produced 193 barrels the first 24 hours after shot. 2.--Approximately 300 acres were developed by 7 wells in the Clinton sand in Perry Township, Coshocton County. The area is so spotty that no acreage is considered proved. Average initial was 38 barrels. 3.--In Washington Township, Holmes County, 7 wells averaged 40 barrels in the Berea sand at 700 feet and developed 100 acres and proved about 100 more. 4.--One hundred forty-five Berea sand wells were drilled in Ashland County during the year. Eighty-one produced oil and developed approximately 250 acres. The Berea is primarily a channel deposit in this area so that almost every new location must be drilled to be proved. Six sub-Trenton wells were drilled. The deepest was the Benedum-Trees' Corlett No. 1, Lot H, Lenox Township, Ashtabula County. The St. Peter sand was found from 5,975 to 5,993 feet and contained salt water. Siliceous dolomite occurred from 5,993 to 6,186 feet, the total depth. The Lancaster Gas Works' Brown No. 1 located in Section 3, Amanda Township, Fairfield County, encountered salt water and a showing of oil in the St. Peter at 3,263 feet. Analysis of the samples below the base of the Trenton limestone has not been completed for these two wells so it is not known if they are geologically important. End_of_Article - Last_Page 1062------------

In 1950, total wells drilled in West Virginia, reported to March 7, 1951, number 744, an increase of 44 over 1949, or 6+ per cent. Permits to drill total 848, an increase of 35 over 1949, or 4+ per cent. Wells abandoned under abandonment permits total 802, including 275 gas wells and 527 oil wells. These are wells drilled before May, 1929. Wells drilled since that date, when abandoned, are abandoned under the original drilling-permit number. Information is lacking for the second half of 1950, but 2 oil wells and 63 gas wells are reported for the first half of the year as abandoned under original drilling-permit number. Wells completed were: gas, 417; oil, 106; oil and gas wells, 34; storage, brine, water-intake, and pressure wells, 30; dry holes, 157. Compared with 1949, as wells decreased 10; oil wells increased 28; oil and gas wells increased 10; storage et al. wells increased 3; and dry holes increased 13. Percentage of dry holes was 21, up about ½ per cent over 1949. Depth of wells completed ranged from 220 to 6,097 feet, compared with 56 to 8,635 feet in 1949. One well is shut down at 9,085 feet. Total footage drilled increased 78,465 feet over 1949, or approximately 4.1 per cent. The average of wells (2,668 feet) was 56 feet less than in 1949. The total initial daily open flow of the gas wells was 468,334 MCF, an increase of 116,217 MCF, or 33 per cent. The size of the gas wells ranged from 11 to 25,000 MCF, compared with 6 to 25,000 MCF in 1949. The total daily initial oil in 1950 was 1,528¼ barrels, an increase of 685½ barrels over 1949, or 81 1/3 per cent. Size of oil wells ranged from ¼ barrel to 80 barrels, compared with ¼ barrel to 50 barrels in 1949. The number of wells drilling or unreported if completed at the end of the year was 313, an increase of 42 over the previous year. Letters were sent to 193 operators regarding 457 wells not reported. Replies were received from 115 operators regarding 356 wells, leaving 78 operators unheard from regarding 101 wells. Preliminary estimates of production for 1950: gas, 197,210,000 MCF; oil, 2,788,000 barrels. Estimated number of producing wells at end of 1950: gas, 13,875; oil, 14,575. A table gives statistics by counties.

The United States has become a nation of marginal oil and gas wells. Well abandonments have become commonplace, and each decline cycle in the price of oil and gas brings on a new round of well abandonments. Yet, we know that the majority of oil and gas resources in developed areas are still in the reservoirs. The plugging and abandonment (P&A) of oil and gas wells because of economic conditions is a byproduct of our market economy, and is a "fact of life" in our business. Typically, a well is abandoned because it has fallen below its economic limit, an arbitrary production rate depending, in part, on the present price of oil and gas. Economic forces are not alone in dictating well abandonment. The timely abandonment of wells is prompted by state regulatory agencies, who must rigidly enforce abandonment statutes for environmental and bonding reasons. The dilemma brought on by P&A is the damage usually done to the well which precludes inexpensive future access to the reservoir. This is mainly because of damage resulting from the salvaging of casing strings in the well at the time of abandonment. Most oil and gas producing states either allow or even require the recovery of casing during well abandonment. While of questionable economic value, this procedure is commonplace and virtually eliminates future reentry into the wellbore. This paper discusses the rationale and economic considerations inherent in the P&A process. It suggests a means for regulating the abandonment of oil and gas wells without removing casing strings, while satisfying concerns of environmental damage downhole.

The total number of wells drilled in West Virginia in 1960, reported to February 22, 1961, was 1,216, an increase of 311, or 34%. Permits to drill or deepen issued by the Oil and Gas Division of the West Virginia Department of Mines totaled 1,349, an increase of 342, or 34%. 79 permits to drill were cancelled during the year. Abandoned during the year were 200 gas wells and 212 oil wells, a total of 412 wells. These abandonments are all wells drilled before permits were required (May, 1929). No information about the exact number of abandonments of wells drilled since May, 1929, is available as these wells are abandoned under original drilling permit numbers. Wells completed were: gas, 794; oil 49; oil and gas wells, 182; storage, water-injection, brine, rock salt, and pressure wells, 49; dry holes 142; total 1,216. Compared with 1959, gas wells increased 203, or 34%; oil wells increased 12, or 32%; oil and gas wells increased 87, or 91%; storage and other wells decreased 10, or 20% with some being drilled for gas storage; dry holes increased 19, or 15%, the percentage of dry holes to total completions being slightly over 11%. Depth of wells ranged from 370 to 13,121 ft, compared with 206 to 8,635 ft. in 1959. Total footage drilled was 2,908,817 ft., an increase of 687,343 ft., or 29% over 1959 (2,321,474 ft.). The average depth of wells (2,392 ft.) decreased 173 ft. under the 1959 average (2,565 ft.), or 712%. The total initial daily open flow of the gas wells was 983,422 MCF, an increase of 295,301 MCF, or 43%, over the 1959 total (688,121 MCF). The size of the gas wells ranged from 10 to 28,400 MCF, compared with 4 to 39,680 MCF in 1959. The total daily initial oil was 4,11712 bbls., an increase of 709 bbls. over 1959 (3,40812 bbls.) or 28%. The size of the oil wells ranged from 12 to 300 bbls., compared with 12 to 220 bbls. in 1959. The number of wells drilling or unreported if completed at the end of the year was 529. 82 more than in 1959, or an increase of 18%. Since we receive drilling and scout reports from several major companies, the status of practically every drilling well was known and no letters were sent to the operators regarding their uncompleted wells. It is believed the total completions will be greater than herein reported as also the production since many wells were reported as testing after fracture. The total initial gas production after fracture is generally several times the production before fracture. Several hundred wells were fractured during the year. The West Virginia University collects information concerning fracturing of wells and issues an annual report showing details for each of the wells fractured. The average size of gas wells was 1,111 MCF, compared with 1,003 MCF in 1959, an increase of 108 MCF or 11%. In calculating this average the number of gas wells was increased by one-half of the number of oil and gas wells (91) or 885 wells. The average size of the oil wells was 29 bbls. compared with 40 bbls. in 1959, a decrease of 11 bbls., or 2712%. One-half the oil and gas wells (19) was added to the 49 oil wells in calculating this average. Preliminary estimates of production for 1960: gas, 207,000,000 MCF, compared with 205,000,000 MCF in 1959; an increase of 2,000,000 MCF or approximately 1%; oil, 2,300,000 bbls., an increase of 116,000 bbls. over the 1959 estimate (2,184,000 bbls.) or 5 1/3%. The estimated number of producing wells at the end of 1960: gas, 16,485; oil, 12,669. The table of operations gives statistics by counties.

The discoveries of relatively large volumes of gas in the Oriskany sandstone in the Wayne-Dundee field in Schuyler County, New York, in March, 1930, and in the Tioga field in Tioga County, Pennsylvania, in September, 1930, first focused attention on this Lower Devonian formation as a potential source of gas in the northern Appalachian Plateau province. The areal distribution, thickness, and physical characteristics of the Oriskany sandstone are described. Most of the Oriskany gas production in the northern part of the province has come from eight pools located in south-central New York and north-central Pennsylvania. Their location, size, structure, and other pertinent features are described. Oil in commercial quantities in the Oriskany has been encountered in only two sm ll pools in eastern Ohio. Analyses of connate waters from the Oriskany sandstone from several widely separated areas are given. A relationship between the composition of the hydrocarbon gases found in the Oriskany and the degree of metamorphism of the associated strata is pointed out. Possible reserves in the Oriskany in Pennsylvania are discussed.

Determining the effect of the fluid properties extracted from the reservoirs together with the produced gas on the pressure loss in wellbores is an urgent task for many fields and underground gas storages. The similarity parameters clarification of gas-liquid flows in pipes and creation of new modeling methods based on them make it possible to increase the degree of validity of the assigned technological modes at all stages of operation of field facilities containing a liquid phase in the products. Previous experimental studies have made it possible to establish an unambiguous dependence of pressure losses in the well on the amount of fluid represented by condensation water. However, the question of the effect of fluid properties on pressure losses in the path of formation mixture movement from the bottom to the installation of integrated gas treatment remains open. The article describes experimental studies of gas-liquid flows with liquids of high density, allowing us to make appropriate changes to the calculation formulas. Based on the methods of similarity and dimensions, corrections to the parameters included in the calculated relationships are concretized, conclusions of new formulas are given that take into account the influence of the liquid phase density on pressure losses in well bores. The structure of a new similarity parameter, the clarified Buzinov parameter, is substantiated, which allows us to most accurately calculate the stable operating modes of gas wells in fields and underground gas storage with an aqueous phase of various salinity. Relations for quantitative estimates of the effect of reducing pressure losses in gas-liquid flows due to wetting of the inner surface of elevator pipes are presented for the first time.

Summary The operation of underground gas storages may be accompanied by deterioration of the technical condition of wells. This is due primarily to the variables of temperature and pressure loads of the element in the wellbore during injection and extraction of gas, which most from the earth’s surface and to a depth of 500–700 m. Under the influence of these factors disrupted the adhesion of cement to casing and formation, occur the leakage of columns, gas leakage from the wellbore, the accumulation of gas behind the columns and headers, behind-the-casing flows from the storage reservoir into the overlying sediments. All this results in considerable industrial gas accumulations, the complication safe operation of UGS and disturbance of the ecological situation in the area. Therefore, the development of the technology search wells — sources of technogenesis, elimination of leaks and cross-flows of gas in them is an urgent task for underground gas storage. The work deals with the identification of cross-flows in the wells of underground gas storages. We consider mathematical models and algorithms for identifying cross-flows according to the thermometer wells. Examples of the interpretation and processing of data, previous studies of wells, underground gas storage.

The leakage of the injection–production string is one of the important hidden dangers for the safe and efficient operation of underground salt cavern gas storage. Although distributed fiber optic temperature measurement system (DTS) can accurately locate the position of the string leakage port, how to establish the quantitative relationship between the temperature difference and leakage rate of the leakage port still needs further exploration. This paper proposes a new quantitative prediction model based on a DTS for the leakage monitoring of the injection–production string of salt cavern gas storage. The model takes into account the gas’s physical parameters, unstable temperature conditions, and the Joule–Thomson effect. In order to verify the accuracy of the model, a simulation experiment of string leakage based on a DTS was carried out. The test results show that the relative deviation between the predicted leakage rate and the measured value is less than 5% compared with the calculated value. When the leakage rate drops to 0.16 m3/h and the temperature range is less than 0.5 °C, it is difficult to accurately monitor the DTS. The results of this study help to improve the early warning time of underground salt cavern gas storage string leakage.

An original polymer technology, successfully used in Underground Gas Storage (UGS) wells, has been recently applied in offshore gas producing wells. Many gas wells in this area are facing combined water and sand problems due to reservoir depletion, water entries and clayey formation. To avoid critical problems connected to water/sand production, the most common action has been so far to reduce gas production by choking down the wells. The new technique consists of bullhead injection of water soluble polymers with the main objective to form an adsorbed polymer layer on the surface of the rock, thus providing stabilization. In addition, the products have RPM properties (Relative Permeability Modifiers). They have little impact on gas permeability while strongly reducing water permeability. The combination of both effects will result in a reduction of water and sand production. Laboratory studies were performed to optimize polymer formulation and evaluate flow properties in reservoir cores. Because of the low reservoir rock permeability (around 10-20 mD), high focus was put on polymer injectivity and RPM effects. Since 2013, nine offshore gas wells have been treated with polymers. Treatments have shown positive results combining gas rate increase up to 100% and water reduction around 50% while stopping the sand. Details regarding well and polymer selection, job design, execution and production data are provided.

Canada has played a prominent role in the development of horizontal drilling technology. To date, over 1,400 "grassroots" and "re-entry" wells have been drilled. Although other countries have experienced greater numbers of wells, the number of different types, varieties, and formations tested with this technology in Canada is unparalleled. Due in part to the exponential growth of horizontal well applications since the mid-1980's, coiled tubing CCT) technology in Canada has been adapted and evolved for more traditional uses such as horizontal well stimulation, evaluation, workovers, and clean-outs. The principal nontraditional aspect of CT is its use in drilling operations. This paper will deal with the current state and recent advances in CT horizontal drilling in Canada, A brief historical perspective will be presented that highlights Canada's presence as a pioneer in CT drilling and documents its evolution from vertical re-entries dating back to 1974, grassroots vertical wells in 1976, to the industry's current efforts at vertical and horizontal CTD. The principal Canadian service companies are reviewed in terms of present capabilities in CTO applications and the perceived driving forces that are stimulating the development of this emerging technology. The key factors such as diameter and fatigue life of the coil, length limitations, bottom hole assemblies, surveying methods and the economic and market factors affecting CTO relative to more conventional drilling techniques are reviewed. Finally, the future technological, market and economic developments necessary for the successful implementation of CTO for grassroots vertical and horizontal well re-entry projects are suggested. Introduction The exponential growth in the number of horizontal well applications in Canada and internationally over the past eight years has led to a relatively rapid development of both personnel and equipment to enhance the horizontal drilling method of exploiting existing oil and gas pools. In Canada, there are an estimated 70,000 producing wells: 40,000 gas wells and 30,000 oil wells. Recently, the National Energy Board (NEB) presented a study on horizontal oil wells and their impact on future crude oil supply in Canada. They estimated that there is a potential market of over 12,000 horizontal wells that can be economically drilled within 1,800 oil pools at a market price of $20 US/Bbl. Of these 12,000 wells, 5,000 were believed to be grassroots in nature (1 I 100 have been drilled to date) while 7,000 were horizontal re-entries through existing cased wells (300 have been drilled to date). Of the 6,700 remaining re-entries, the competition for services will be between slim hole (less than or equal to 6–1/4 in. hole size) conventional drilling systems using drilling rigs or modified service rigs and coiled tubing drilling (CTD) technology. Add to this potential market vertical deepenings, horizontal lengthenings and grassroots wells coupled with increasing interest in horizontal exploitation of gas pools, and the development of CTD appears to be poised for exponential growth in Canada over the next five years. Some of the questions that will be addressed during the course of this paper are:

Experimental investigation and predictive modeling of dry-out and salt precipitation effects during underground gas storage operations

The storage of natural gas in geological structures such as depleted fields, aquifers and salt caverns plays an important role in a gas supply system as it balances the fluctuation of gas demand and price. Hydraulic loss due to fluid flow through gas storage production equipment and an interfering effect from nonequal productivity index of storage wells may have an important influence on gas storage performance. An integrated mathematical model is developed based on underground gas storage facility production data. Using this model, the hydraulic loss is determined. A real test case that consists of a gas storage reservoir linked to the surface facility is analysed. The mathematical model uses an experimentally determined pressure drop coefficient in chokes. The base case scenario created using real gas storage facility data enables the achievement of a good history match with the given parameters of the gas storage reservoir. Using the history match simulation case as an initial scenario (a base case), two different scenarios are created to determine the injection and withdrawal performance of the gas storage field. The results indicate that the pressure drop in chokes, when fully open as a constraints in an underground gas storage facility, has a significant impact on gas storage operations and deliverability.

A novel method based on injection of silicone microemulsion was developed for restriction of water production in gas wells. The treating solution was a surfactant stabilized siloxane emulsion which was driven into the formation by water and nitrogen. According to the laboratory studies disproportional permeability modification is in the background of the water retention. The phenomena is attributed to inversion of microemulsion to macroemulsion initiated by spontaneous dilution by water and then entrapping of formed siloxane droplets by the pores. The method was tested at the largest Hungarian gas field (Algyő field, Hungary). Evaluation of the pilot test has definitely proved the beneficial effect of silicone injection on gas production and gas/water ratio: the gas production tripled and lasted for at least a half year. The encouraging results urged the operator to continue both the laboratory and the field tests with the aim at developing a method which might be used routinely in low permeable, tough gas fields and underground gas storage.

During the year 1942, 26,474,610 barrels of oil and distillate were produced in South Arkansas and 32,491,304 barrels in North Louisiana. In December, 1942, there were 3,041 oil and distillate producing wells in South Arkansas and 4,494 wells in North Louisiana. Two hundred fourteen wells were drilled in South Arkansas during 1942 with the total footage of 1,094,223 feet. In North Louisiana, 527 wells were drilled with the total footage of 2,257,530 feet. The average depth of wells drilled in South Arkansas during 1942 was 5,113 feet compared with 4,121 feet during the year of 1941; for North Louisiana, the average depth for 1942 was 4,280 compared with 2,952 feet for the year of 1941. Of the total of 741 wells drilled in South Arkansas and North Louisiana, 400 were oil wells, 81 were gas and gas-distillate wells, 125 were dry holes in fields, and 135 were wildcat dry holes. The major discovery in South Arkansas during 1942 was the Midway field in Lafayette County, producing oil from the Smackover limestone. Smackover limestone gas-distillate production was discovered in the Columbia field in Columbia County, and in the Texarkana field in Miller County. The New London field in Union County, a 1942 discovery, produces oil from several sands in the lower Cotton Valley section. Cotton Valley sand production was also discovered in three Smackover limestone producing fields: oil in the McKamie field, Lafayette County, and gas-distillate in the Dorcheat and Macedonia fields in Columbia County. In North Louisiana during 1942, three Wilcox sand oil fields were discovered in La Salle Parish, and the Lake St. John Wilcox sand field in Concordia Parish. The latter field also produced gas-distillate in the basal Tuscaloosa (Upper Cretaceous) sand in the deep discovery well. A Sparta sand gas well was completed in the Lake St. John field, a Sparta sand oil well in Catahoula Parish, and two Cockfield sand oil wells in the Nebo field. A Paluxy sand gas-distillate producer was discovered in Winn Parish. A small oil well was completed in a Cotton Valley sand northeast of the Monroe gas field in Morehouse Parish. A new Pettit limestone field was discovered near the Louisiana-Arkansas state line in the North Cartersville area.

Summary The Hutubi (HTB) gas reservoir in northwest China was active in production from 1998 to 2012; beginning in 2013, it was used for gas storage. Several earthquakes occurred during the early operation of the Hutubi underground gas storage (HTB-UGS) project, so it is important to explore their relationship with gas injection and extraction from the viewpoint of stress state change and faulting susceptibility. We study the evolution of the stress state and slip tendency associated with the operation of the HTB-UGS to understand the relationship between pore pressure variation and induced seismicity. We constrain the stress state in the reservoir at the time of cessation of production in 2012 using image-logged wellbore breakouts. We then estimate stress state variation over time as a result of pore pressure changes, based on the assumption of poroelastic coupling between horizontal elastic stresses and pore pressure. The maximum principal stress in the reservoir region before the HTB-UGS operation is oriented N23°±6°E, which is consistent with that of the prevailing tectonic stress derived from earthquake focal mechanisms. Our results show that the vertical stress (Sv) and the minimum horizontal principal stress (Shmin) were initially similar in magnitude before petroleum production; the magnitude of Shmin gradually decreased during petroleum production. Gas injection, initiated in 2013, raised the Shmin magnitude, returning it to approximately that of Sv. We use the estimated variations in the reservoir stress state over time to calculate temporal changes in slip tendency of the main faults in the reservoir. The fault-slip tendency decreased continuously with petroleum production and then increased with gas injection. The first earthquake swarm associated with gas injection occurred approximately 2 months after the start of injection, possibly due to the slow pore pressure diffusion. Thereafter, earthquakes were induced whenever gas was injected. Our assessment of slip tendency suggests that earthquake swarms were induced during increasing pore pressure phases when slip tendency reached a value of 0.43 ± 0.04. The maximum allowable pore pressure for avoiding earthquakes (ML > 1.5) is 29.0 ± 4.5 MPa, which might increase through stress adjustments and a newly attained balance. This study provides a possible method for induced earthquake analysis associated with gas injection and extraction from the perspective of stress state change and faulting susceptibility.