Developments in Ohio in 1951

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.

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.

Scenery Hill, a small village in West Bethlehem Township, Washington County, Pennsylvania, 25 miles southeast of the famous McKeesport field, was the scene of unusual activity in the spring of 1927, when the first gas well was completed in that field. Since that time thirty-six wells, sixteen of which were dry holes, have been drilled within a radius of 1 mile. Local domes located on a plunging syncline afforded an ideal condition for the segregation of gas, oil, and water. Unfavorable sand conditions caused many dry holes. Twenty wells produced 1,500,000,000 cubic feet of gas, with original rock pressures varying from 1,000 to 1,200 pounds. Production was largely from the Fifth sand. This compares on a small scale with the McKeesport field production of 22,000,000,000 cubic feet of gas from approximately 800 wells. Production reached its peak during November, 1927, when fifteen wells produced 454,600,000 cubic feet of gas. By August, 1928, there were only four producing wells, sixteen having been abandoned. The four active wells produced only 3,556,000 cubic feet of gas in July, 1928, these being operated on a vacuum.

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.

Red mud is a waste byproduct of aluminum production that can pose significant environmental challenges. However, recent studies have shown that red mud can be used as a raw material for geopolymer cement for construction purposes, which could also potentially have applications in the oil and gas industry. This paper aims to review the potential of red mud-based geopolymer cement for use in oil and gas wells, including its chances, possibilities, and complications. Geopolymer cement has several advantages over traditional Portland cement, including lower carbon emissions, improved durability, and higher resistance to chemical attack. However, the production of geopolymer cement typically requires the use of high-quality raw materials, which can be expensive and may not be readily available in all locations. Red mud is a waste material that is generated during the extraction of alumina from bauxite ore. Red mud contains significant amounts of alumina, silica, and iron oxide, which are the primary components for geopolymer cement production. Consequently, red mud possesses the potential to be a low-cost and readily available source of raw materials for geopolymer production. Many research studies have explored the application of geopolymer cement derived from red mud for diverse purposes, including construction materials, wastewater treatment, and soil stabilization. However, red mud-based geopolymers for oil and gas wells are relatively unexplored. Oil and gas wells require cement with high compressive strength, low permeability, and resistance to high temperatures and aggressive chemicals. Therefore, the potential of red mud-based geopolymer cement to be used in oil and gas wells is an interesting topic for further investigation. This paper reviews some existing literature on the use of red mud-based geopolymer cement and its potential applications for well cementing. The review will focus on the key properties of red mud-based geopolymer cement. The review will also discuss the challenges and complications accompanying the use of red mud-based geopolymer cement in oil wells, such as the potential for corrosion and the effects of different types of oilfield fluids on the cement properties. In conclusion, red mud-based geopolymer cement has the potential to be a cost-effective and environmentally friendly alternative to traditional Portland cement in oil and gas wells. However, further research is needed to fully evaluate the suitability of red mud to be incorporated in well cementing, and to address the challenges and complications associated with this application.

Corrosion is a common problem in oil, gas, and water wells. It has ability to cease the deliverability of oil wells and has significantly affected ultimate recovery from existing oil fields. Due to the limitation of continuous downhole corrosion monitoring or use of corrosion logging tools which are not continuous determination of precise rate of corrosion becomes extremely challenging. To overcome this shortcoming, a novel downhole corrosion system has been devised. This paper outlines a strategy for the successful implementation of a distinctive approach to measure downhole corrosion and scale using a mechanical cylindrical coupon system with noteworthy enhancement in the life of completions jewelry at one of the largest onshore oilfields. Methods, Procedures, Process This rig-less technique incorporates introduction of downhole corrosion coupon which is installed inside an exclusively designed corrosion monitoring valve or gauge hanger with lock mandrel or high expansion gauge hanger with non-explosive setting tool. These distinctive systems are developed not only to overpower the technological drawbacks of conventional systems, but also accurately measure downhole corrosion and scale in oil, gas and water wells which are completed with gas lift completions, nipple less completion or completions with profile nipples to transform well lifecycle. Formulation of well selection criteria, individual well sampling and assessment, proper data gathering, data analysis, application methodology and custom-made design of well programs have made it possible to operate wells under safe condition and are capable to function continuously to achieve the targeted production requirements. Results, Observations, Conclusions A pilot project on nine wells for a major operator in the middle east exhibited a significant improvement to measure downhole corrosion rates and enhance well life by designing an effective chemical treatment program to mitigate downhole issues. This reduced the frequency of workovers worth savings of $50M and eradicated downtime for production operations. Application of this technology has broken the barrier in evaluation of these wells and provides an effective means of diagnosing the wells with well integrity issues beyond the capability of standard corrosion and scale monitoring methods. It is a cost-effective technology to identify downhole integrity issues and enhance the field value from existing wells. Additive Information This paper considers selection methodology and scenarios that help to estimate potential well integrity challenges and formulate downhole chemical treatment program for elevation of downhole tubulars run life and recommends suitable actions which allow well integrity engineers to take timely actions for sustaining production from oil and gas wells. The paper will also discuss the role of this technology in the overall well construction workflow. With the increased complexity of mature fields, each next step to improve recovery comes with increased cost. Therefore, novel horizons of affordable technology will play a pivotal role to maximize economic recovery and meet rising demand in the current business environment.

The United States National Science Foundation has funded a Sustainability Research Network (SRN) focused on natural gas development in the Rocky Mountain region of the United States. The objective of this specific study is the assessment of the use of existing water wells to monitor the risk of the contamination by the migration of fracturing fluids or hydrocarbons to fresh water aquifers. An additional objective of the study is to modify existing risk estimates using the spacial relationships between the existing water wells and producing oil wells. This will allow estimates of single barrier failure and multiple barrier failure resulting in contamination to be projected for oil and gas wells in areas without surrounding water wells to detect migration, based on well construction type. Since 1970, the Wattenberg Field in Colorado has a large number of oil and gas wells drilled. These wells are interspaced tightly with agricultural and urban development from the nearby Denver Metropolitan area. This provides a setting with numerous water wells that have been drilled within this area of active petroleum development. Data from 17,948 wells drilled was collected and analyzed in the Wattenberg field, allowing wells to be classified by construction type and analyzed for barrier failure and source of aquifer contamination. The assessment confirms that while natural gas migration has occurred in poorly constructed wellbores is infrequent, it can happen and that the migration risk is determined by the well construction standards. The assessment also confirms that there has been no occurrence of hydraulic fracturing fluid contamination of fresh water aquifers through wellbores. The assessment determines both the spacial proximity of oil and gas wells and surface casing depth to water wells to determine the utility of water wells to monitor migration in oil wells.

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With a contribution of about one third, methane is the second most important greenhouse gas in the climate system. In addition to a biogenic formation, e.g. in wetlands, methane also is emitted during anthropogenic industrial activities. BGR is investigating abandoned onshore oil and gas wells in Germany, which are generally plugged and buried, for their relevance as sources of methane. Initial results from studied wells examined so far (about 75 wells) indicated no or very low methane emissions at very few sites. A controlling process for low methane emissions for the wells could be microbial methane oxidation, which is an important process in organic-rich soils overlying wells in Northern Germany (Jordan et al., accepted).We present here data from soil above a plugged oil well, drilled in the early 1920s and located at Nienhagen near Hannover (Germany). At the well ~40 mg CH4 h-1 were emitted (average range for plugged US oil wells ~50 to 170 mg h-1 per well; Williams et al. 2021). Gas geochemical analyses of the soil gas confirm the presence of natural gas (up to 8 % methane and 600 ppm ethane) and the δ13C of the methane supports that the majority is thermogenic (-47.1 ‰). In addition to natural gas, we also found petroleum in the soil, which reached up to 80 % soil total organic carbon. Our data suggest a complex mosaic of hydrocarbon-altering effects dominated by products from the microbial degradation of well-derived oil and natural gas (e.g., propane oxidation). It is likely that O2 availability controls the degradation of petroleum in the soil under investigation, because the strongest degree of degradation was found in the upper soil horizons. The properties of the formerly produced oil exclude biodegradation in the reservoir, so the degraded oil must have been formed during the ascent or in the topsoil. The gas geochemical composition of the soil gases indicates also deeper, anaerobic processes, such as methanogenesis, probably with petroleum as the carbon source. Soil microcosms from different depths showed, indeed, a rapid onset of microbial degradation of added oil both under aerobic and anaerobic conditions in the lab. Although processes in a deeper biosphere appear to play a role here, it is likely that mostly the microbial processes in the soil surrounding the well regulate the composition and quantity of oil and gas. In conclusion, the (i) high degree of degradation in the natural gas components in the soil and petroleum, as well as the overall (ii) only low methane emissions, indicate that the Nienhagen well is only leaking relatively little and that a “microbial hydrocarbon filter” is established and active.ReferencesJordan, S.F.A., Schloemer, S., Krüger, M., Heffner, T., Horn, M.A., Blumenberg, M., (accepted) Preprint. Interferences caused by the microbial methane cycle during the assessment of abandoned oil and gas wells. EGUsphere. doi:10.5194/egusphere-2024-1461Williams J. P., Regehr A. and Kang M. (2021) Methane Emissions from Abandoned Oil and Gas Wells in Canada and the United States. Environmental Science & Technology 55, 563–570.

Corrosion problems of deep well tubings and their control measures are discussed. As one of the economical solutions, metal-lined tubings are proposed. It is shown that the metal liner can be tightly fitted by the newly developed thermo-hydraulic fit method. The selection of corrosion-resistant material for the liner is discussed. Some designs of the tubing joint and their manufacturing methods pre proposed. Introduction With the seriousness of an energy shortage, the drillings of oil and gas wells have become more active. In the last few years, the number of drilled wells has increased rapidly as shown in Fig. 1. It should be noted that eighty percent of these wells were drilled in the United States. Fig. 2 shows the depth distribution of oil and gas wells drilled in the United States in 1977. It can be seen that the numbers of oil and gas wells are about the same, but, in general, there are more gas wells at deeper depths than oil wells. As shown in Fig. 3, well depth increases each year, and recently an exploratory well deeper than 10,000 m has been drilled. As the well depth increases, the down hole pressure and temperature rise. For instance, in some severe wells at a depth of 6,000 m, the pressure and temperature are more than 1,000 bar and 200°C respec. tively. Therefore, the strength of the tubings used in such severe conditions is a very important factor for deep wells because they have to sustain their ownweight also. Figure 4 diagrammatically illustrates the transitions of design conditions with the increaseof well depth. Figure 5 shows the relationship between well depth and axial and hoop stresses of API standard tubings with various pipe 'dimensions. It isknown roughly that the strength of class P-I05 is required for the tubing of a 6,000 m well. Another substantial problem in deep oil and gas wells is corrosion. This is mainly due to H2S and C02 which are contained in crude oil and natural gas The density of these contaminants is increased with well depth, and, together with high pressure and high temperature, the corrosion reaction is accelerated. To solve all the above problems in deep wells, a new type of economical, high strength tUbing which has high corrosion resistance is expected. At present a super Ni alloy tubing, which is extremely expensive, tends to be used. As a solution, the authors propose the Tight Fit Tubing (hereinafter referred to as TFT) which is lined inside with corrosion-resistant alloy to meet the above three requirements for the tubing of deep wells. The thermo-hydraulic fit method used here for TFT has been developed to produce the corrosionresistant pipe, TFP, for corrosive flow lines as reported in Ref. 1.

Most current oil and gas wells are drilled with synthetic-based muds. During drilling, two types of wastes: spent muds and drilled cuttings, are generally generated. Several methods are used in the treatment of these wastes. However, after treatment of these wastes, they are disposed into the environment. Although they seem to be environmentally friendly, greater accumulation may degrade the environment. Nonetheless, some additives used in cement slurry formulation are also present in most of the spent drilling muds, therefore they could be stabilised for reuse in oil and gas wells cementing operations. In recent times, lime is used to stabilise spent synthetic-based drilling mud before disposal or for further treatment. These lime-stabilised muds find use as feedstock of cement kiln, raw material for the production of construction material and wetland restoration materials. This research studies the performance of blended lime-stabilised drilling mud and cement at varied concentrations for oil and gas wells cementing operations. The cement was blended with lime-stabilised mud with concentrations from 0% to 100% at a step of 10% and their properties evaluated. Slurry properties like density, free fluid, rheology and compressive strength results obtained showed that these properties decreased with the increase in percentage blend of the lime-stabilised spent synthetic-based mud. However, it was observed that concentrations of 10% and 20% blends of lime-stabilised mud with cement performed better with good potential to be considered in minor cementing works by the industry to help reduce the cost of waste management. Cited as : Amorin, R., Opoku Appau, P., Osei, E. Evaluation of blended lime-stabilised spent synthetic-based drilling mud and cement for oil well cementing operations. Advances in Geo-Energy Research, 2019, 3(2): 141-148, doi: 10.26804/ager.2019.02.03

The Lloydminster heavy oil area has experienced an erratic growth since the first commercial oil was discovered in 1943. Prior to a tie-in to Interprovincial Pipeline to the east in 1963, the demand for the oil was very limited, resulting in an historic low price of the crude oil At the present time the field is producing about 35,000 BOPD. Husky Oil Operations Ltd. has over 1,200 oil, gas and service wells and produces about 28,000 BOPD of the total field output. The oil and reservoir characteristics make production of the oil difficult, with oil recoveries by primary or waterflood means very low. The highly viscous oil, coupled with the fine-grained, unconsolidated sandstone reservoir, results in high rates of sand production with the oil. The low-temperature reservoirs seem a natural for some type of heat drive or stimulation process. However, cyclic steam and steam drive operations have not proved economical Results to date of a modified in-situ combustion process are encouraging. This process is expensive, requires close technical attention and presents some special operational problems. However, if successful, it will provide a several fold increase in total oil recoveries over present methods. We are confident that this process, or others that will be developed as our technology improves, will enable the vast Lloydminster Field to maintain its dominant position as the heavy oil center of Western Canada for many years to come. Introduction THE OIL AND GAS INDUSTRY in the Lloydminster areastraddling the Alberta-Saskatchewan border dates back to 1934 when the Lloydminster Gas Company completed the first commercial well in Saskatchewan as a gas producer just southeast of Lloydminster. This discovery allowed Lloydminster to become one of the first communities in Western Canada to be serviced by natural gas. Follow-up drilling resulted in additional gas wells and some indications of the presence of a heavy, black asphaltic-base crude oil. The first oil well was completed in 1938, but the first actual commercial production was not available until 1943. The total oil production through 1945 was only about 50,000 barrels, which was used locally for the production of Bunker C fuel for the railroads. It was processed in a small refinery that went on stream in 1943, operated by Exelsior Petroleum. Husky Oil Company entered the picture in 1946 with the movement of a 1,500-barre.lfday refinery from Wyoming to Lloydminster. The following year, the refinery capacity was increased to 2,500 barrels per day and Husky obtained its first oil production to help assume a steady supply of crude for the refinery. By 1955, the field contained over 700 wells and was producing almost 3,000,000 barrels of oil per year All of the fuel oils and asphalt produced at the local refinery were consumed in the region. However, as the railroads converted from steam to diesel engines, the demand for Bunker C fuel oil declined sharply. By the early 1960's, Husky was producing less than one-half of its 180 capable oil wells and was desperately searching for additional markets for the region's crude.

The U.S. Department of Energy, Petroleum Consulting Services, Universal Well Services, and Canadian Fracmaster have recently performed eight CO2/sand stimulations on four Devonian Shale gas wells in the Appalachian Basin. Four two-stage CO2/sand stimulations were executed with two operators in the Pike and Martin County, Kentucky area. All stimulätions involved 120 tons of carbon dioxide (CO2) and up to 47,500 pounds of sand. In addition, there are eleven existing control wells stimulated with four two-stage foam fracs and seven two-stage nitrogen fracs. Production results from these fifteen wells are compared. After nine months of production, CO2/sand fractured wells in the Pike County, Kentucky study area are nearly twice as productive as nitrogen gas fraced wells and nearly five times better than the foam fraced wells in the study group. The per well incremental gas production after nine months ranged from 13.5-22.2 MMcf per well for nitrogen gas and foam fraced wells, respectively. Discussion of the CO2/sand treatment parameters, job execution, and a representative pressure/injection response are discussed in detail. As the operators begin to utilize the CO2/ sand frac process on more wells, the new stimulation process will become commercially available on a routine basis.

Dimensionless IPR curves for predicting the current and future performance of both unfractured gas wells, and fractured gas wells with positive, negative, or zero skin factors are presented in this paper. An example is presented in which the current and future performance of a gas well is forecasted and compared to the results obtained from a modified isochronal test.

Cement is used as the primary sealant in oil and gas wells throughout the world and is manufactured to meet specific chemical and physical standards set up by the American Petroleum Institute (API). As a result, oil companies purchase cement manufactured according to specification of API for its oil well cementing. These special classes of cements are called Oil Well Cements (OWCs). In oil well cementing, less error is tolerated in the performance of the cement used as compared to conventional cementing work. This has resulted in more attention being placed on the usage of high grade API special class of cements as against any ordinary type of cement. However, there are some cementing operations that Construction Grade Cements (CGCs) have been used without resulting in any cementing challenges. This paper presents the progressions in experimental investigations and field applications of CGCs in oil well cementing. The experimental investigations on the physical properties such as thickening time and rheological properties revealed that local cements in its natural state lack sufficient technical properties for oil well cementing. However, with the right addition of oil well additives, local cements have proven to have the required technical properties for oil well cementing. Countries like Vietnam and Thailand have demonstrated the field applications potentials of CGC. Comparing the cost of CGCs and OWCs (imported), it is realised that more savings are made when CGCs are used in cementing operations.