Gas Storage Wells Research Articles

Influence of added hydrogen on underground gas storage: a review of key issues

The existing infrastructure of the natural gas transportation pipeline network and underground gas storage (UGS) facilities in Germany provides an opportunity and huge capacity to feed, transport and store hydrogen and synthetic fuel gases containing hydrogen, produced from renewable sources. At low hydrogen concentrations, only minor changes to gas transportation equipment will be required. In contrast, the UGS designed in converted gas fields and aquifers are particularly susceptible to the effect of hydrogen. Due to a lack of adequate knowledge about the hydrogen concentration in natural gas, which can be tolerated by the downhole equipment, reservoir and caprocks, the injection of natural gas containing hydrogen in the existing porous UGS is strongly limited. Key issues addressed in this paper are the change in capacity and efficiency of UGS associated with the blending of hydrogen in the stored natural gas, the geological integrity of the reservoir and caprocks, the technical integrity of gas storage wells, durability of the materials used for well completions, corrosion and environmental risks associated with the products of microbial metabolism.

Study on Threaded Connection’s Strength in Gas Storage Well Using Finite Element Analysis

Sealing property of threaded connection in gas storage wells is of great importance to the safety operation condition of CNG filling station. Indoor leakage tests of threaded-connect pipes are conducted and mathematical models to calculate the axial and thread contact stresses are established. Moreover, finite element analysis is used to figure out the maximum equivalent Von Mises stress in threaded connection. The results show that strain and stress of tested pipes have the linear distribution regularity. Also, it can be seen from the stress nephogram that the first to fourth pairs of threads bear 40% of the whole load and if the first pair has slip phenomena, other pairs of threads would be affected easily which leads to the possibility of gas storage well leakage.

Fracture Height Containment in the Stimulation of Oriskany Formation

The Oriskany sandstone formation has been a prolific producer of natural gas in the Appalachian basin since 1930s. Lot of production wells have been converted to gas storage wells for the ease of operation. Natural gas storage industry is a vital part of North American energy driven economy because of the fluctuation in seasonal demand and in maintaining the reliability of supply needed to meet the demands of the consumer. However, the storage wells suffer from an annual deliverability loss of 5% owing to the various damage mechanisms. A lot of work pertaining to the issue of identification of damage mechanisms and subsequent development of stimulation technology in order to mitigate the damage and restore the wells deliverability have been done in a joint effort between The Gas Research Institute, Department of Energy, American Gas Association and the various other operator companies involved in the storage industry. Operators mostly rely on traditional methods such as blowing, washing, reperforating, acidizing, infill drilling to restore wells deliverability. These traditional methods do provide short term benefits, but the longevity is not sustained and the overall situation remains same. Hydraulic fracturing is not preferred in terms of legitimate concerns over excessive vertical height growth, long fracture fluid cleanup times, lack of expertise and cost. This research study was carried out to understand the various damage mechanisms affecting the Oriskany wells, with a focus on gas storage wells. We then developed a dataset of reservoir properties, rock properties and fracture treatment data for Oriskany based on a complete literature review and calculations from a sonic log. Parametrical studies were carried out to investigate the effect of type of fracture fluids, injection rate, types of proppant, treatment volume, reservoir pressure and treatment schedule on fracture geometries in the Oriskany formation. Based on the results, we developed new stimulation methods that lead to increased well deliverability, fracture height containment, and higher average fracture conductivity. This new understanding and knowledge help in practicing engineers design better treatments in stimulating Oriskany wells.

Cement-Polymer Composites for Oilwell Cementing

The selection of an optimal cementitious material is critical to maintain zonal isolation for the lifetime of oil & gas or gas storage wells not only for primary cementing but also after well abandonment. Polymer powder/cement composites present good mechanical and durability properties since polymer latex promotes improved adhesion and flexibility to the hardened cement paste. So, for well constructions in aggressive environment, polymer powder/cement composites would be good candidates. During the well construction, the cement slurry placement strongly depends on its rheological behaviour. In this paper, we studied rheological properties of polymer powder/cement composite suspensions: they present a transition from a gel to a liquid behaviour in oscillatory shear. The replacement of cement particles by polymer particles induces a decrease of the storage modulus in the gel state. The good quality of the polymer particle dispersion and their high affinity for cement particles were observed by Scanning Electron Microscopy (SEM). Solid state NMR (29 Si and 27 Al) and calorimetry allowed to highlight the influence of the polymer addition on both the hydration and hardening of the cement matrix. All these results helped us to understand the relations between the slurry composition, its rheological behaviour and the properties of the hardened materials which allowed us to design new cementing materials.

Wettability alteration to increase deliverability of gas production wells

More than 17,000 gas storage wells in the U.S. annually lose about 5% of their deliverability (i.e., injectivity and productivity). A common problem is believed to be water blockage around the wellbore. For strongly water-wet gas reservoirs, capillary forces promote the retention of water in pore spaces, which in turn curtails the flow of gas in and out of the storage wells. This paper reports the use of surfactants to change the water-wetness of a gas reservoir in order to increase gas deliverability. Surfactant treatment can alter the strong water-wetness of the rock around wellbore to a neutral-wet condition, thus reducing water retention and improving gas flow. The objective of this laboratory study was to demonstrate improved gas deliverability by altering the wettability of core samples with proper chemicals from strongly water-wet to neutral-wet. Seven chemicals were screened for efficacy of changing the wettability of strongly water-wet glass capillary tubes. Following the capillary rise tests two surfactants were selected for the core sample experiments. Rock samples and water from the St. Peter formation, a sandstone aquifer gas storage reservoir, have been tested. Spontaneous imbibition tests of reservoir cores were used to evaluate the wettability before and after surfactant treatment. The cores saturated with either initial formation water or surfactant solutions were displaced with wet nitrogen gas. Gas relative permeability was measured. A decrease in the trapped water saturation caused an increase in gas permeability. This increase indicated improved gas deliverability that resulted from wettability alteration away from very strongly water-wet conditions. Laboratory results demonstrated that reducing the water-wetness increased permeability and improved the deliverability of gas from the cores. This technique provides a cost-effective method to increase gas deliverability in fields where water blocking is a major factor in decreased gas deliverability.

Design and performance of a pilot-scale constructed wetland treatment system for natural gas storage produced water

To test the hypothesis that water produced from natural gas storage wells could be treated effectively by constructed wetland treatment systems, a modular pilot-scale system was designed, built, and used for treating gas storage produced waters. Four simulated waters representing the range of contaminant concentrations typical of actual produced waters were treated, and the system’s performance was monitored. Freshwater wetland cells planted with Schoenoplectus californicus and Typha latifolia were used to treat fresh and brackish waters. Saline and hypersaline waters were treated by saltwater wetland cells planted with Spartina alterniflora and by reverse osmosis. Effective removal of cadmium, copper, lead, and zinc was achieved by the pilot-scale system. Results suggest that use of specifically designed constructed wetland treatment systems provides a flexible and effective approach for treating gas storage produced waters over a wide range of compositions.

Lifetime of a Natural Gas Storage Well Assessment of Well-Field Maintenance Cost

Gaz de France has been operating underground gas storage wells since more than 50 years. These wells have been drilled with the current available technologies in oil and gas industry. These technologies had improved a lot in the last decades (slurry compositions, drilling and cementing techniques, etc.) and the lifetime of a well therefore has to be estimated with reference to the techniques in use at the date it was built. These uncertainties and the inaccurate data of the oldest wells (drilling logs and casings specifications) led GDF to investigate the wells lifetime. Two approaches are presented here: - assessing a theoretical lifetime of a well; - calculating the average lifetime of each well using essentially corrosion scenarios and kinetics. Combining the two different approaches, one can better assess well aging and remaining well lifetime in order to schedule the best action (work-over, abandonment) at the proper time. A better knowledge of well's lifetime enables good control of underground storage operational expenditures (OPEX).

Overview: Gas Production Technology (November 2006)

The gas-production and -processing industry continues to apply new technologies, as well as improve old technologies, to produce gas and bring it to market. For many years, gas in remote locations had virtually no value because markets were not within economic reach by pipeline. In recent years, with the increase in the value of oil and the products derived from oil, technologies to convert natural gas chemically to liquid hydrocarbons are being applied to monetize remote gas. This increase in gas-liquefaction capacity is in addition to the older technology that physically changes phases of natural gas from gaseous to liquid by deep cooling for transportation to market. Natural gas often is produced from tight geological formations. To produce gas from low-permeability reservoirs economically, it is necessary to hydraulically fracture the rock. This process requires pumping a large amount of water or a suitable hydrocarbon liquid at high pressure as carrier fluid for the proppant. Minimizing the leakoff of the fluid being pumped enhances the effectiveness of such stimulation treatments. New approaches to the selection of specific fluid additives, designed to reduce surface tension and leakoff, can extend the fracture length and increase the well's productivity. A common hindrance to gas production in low-productivity gas wells is the ever-present problem of coproduction of water. While this problem has been studied extensively in the past, new technology can be combined with existing technology to extend the productive life of low-rate gas wells. For high-pressure gas production, a reduction of the water vapor contained in the produced gas can be achieved through the application of supersonic nozzles, in place of traditional dehydration methods. The above-mentioned topics and other innovations regarding gas production technology were examined in papers presented during the past year at various SPE technical meetings worldwide. Gas Production Technology additional reading available at the SPE eLibrary: www.spe.org SPE 100442 "Selective Removal of Water From Supercritical Natural Gas" by A. Karimi, Memorial U. of Newfoundland, et al. SPE 98285 "Arqumia Field: Mexico's Highest-Deliverability Gas Well" by A.E. Guzmán, SPE, Pemex E&P, et al. SPE 97070 "Identifying the Timing and Sources of Damage in Gas-Storage Wells Using Smart Storage Technology" by J.P. Spivey, SPE, Phoenix Reservoir Engineering, et al.

Frac-Pack Completion of Gas-Storage Wells for Enhanced Deliverability

Summary This case-history paper presents the results of installing frac-pack [one-step tip screenout (TSO)1 fracture stimulation and gravelpack operations]2–5 completions in gas-storage wells in the West Clear Lake field of Harris County, Texas. With the frac-pack technique, operators have fracture-stimulated six wells (new drills and workovers) in the past 3 years as part of an overall facility upgrade. Gas is injected daily into the Frio formation (5,500 ft) of the field and withdrawn at high rates during peak demand periods. A strong waterdrive can "water-out" production at the end of peak-season gas withdrawal. The water recedes when withdrawal is ended and injection restores gas volume and pressure in the reservoir. The paper presents frac-pack installation techniques, performance comparison of conventional methods and frac packs, and completion-technique selection to achieve high production efficiency. New wells that were completed with frac packs in 1994 have yielded rates up to 100 MMcf/D each with approximately 500 psi drawdown pressure. In 1995, a well capable of producing at 25 MMcf/D with a gravel pack was recompleted with a frac pack, which increased its rate capacity to 49 MMcf/D. Because of the performance of the first three wells, three more wells were completed with frac packs in 1997. The frac-pack completion has proven superior to other sand-control methods in providing highrate deliverability in the West Clear Lake field. Frac-pack completions have, in general, provided a two-fold increase in the daily production rate. Frac-pack completions and recompletions can be applied in gas-storage wells where high production rates and sand-control measures are necessary for the life of the well. This paper provides guidelines and results associated with frac packing by Demonstrating the importance of selecting completion techniques that will provide high-efficiency production from gasstorage wells. Presenting case histories of frac-pack-stimulated gas-storagewell performance over a relatively long time period. Comparing well performance of conventionally completedand frac-pack-completed gas-storage wells producing at high rates. Providing insight into the operational aspects of frac-pack completions.

Performance Drivers in Restimulation of Gas-Storage Wells

Summary To maintain or enhance deliverability of gas-storage wells in the Clinton sand in northeast Ohio, an annual restimulation program was established in the late 1960s. The program calls for as many as 20 hydraulic fractures and refractures per year. Several wells have been refractured three to four times, while there are still wells that have only been fractured once in the past 30 years. As the program continues, many wells will be stimulated a second, third, or fourth time. This paper summarizes an attempt to carefully study the response of the Clinton sand to hydraulic fractures and to identify the performance drivers in each series of fracture jobs. Are the performance drivers the same for the later fractures (second, third, and fourth fracture jobs) as they were for the first ones, or do they change? This paper attempts to answer such questions. Identification of major performance drivers becomes important when new jobs are to be designed. They not only play an important role in enhancing the response of the wells to new stimulation jobs, but they also may prove to be an important economic factor in the design of new stimulation procedures. If, for instance, it is concluded that an increase in proppant volume does not influence the stimulation outcome after the second refracture, then fewer resources can be used for proppant volume and can be directed toward parameters that are more influential. This study employs a combined neural-network and fuzzy-logic tool to identify the performance drivers.

Intelligent systems application in candidate selection and treatment of gas storage wells

A series of neural networks and genetic algorithm routines have been used in an integrated and hybrid manner to identify the candidate wells for stimulation in a gas storage field. The intelligent system not only is capable of identifying the candidate wells, but it also recommends whether the well should be chemically treated or hydraulically fractured. Upon the recommendation of the type of the treatment, the intelligent system proposes a recipe for the treatment and forecasts the potential gains that can be expected once the proposed treatment is completed.

Improved treatment of acrylamide co- and terpolymers for water control in gas-producing and storage wells

The main objective of this study was to determine the optimal conditions for application of acrylamide co- and terpolymers for water control in gas wells under various environmental conditions. Starting in February 1992, the limits of application of acrylamide co- and terpolymers were first defined in the laboratory through extensive tests. Based on the results of the comparative feasibility study, four field tests were performed in both gas reservoir and underground gas storage wells. This paper presents the latest results of field tests. Using a partially sulfonated acrylamide terpolymer, the first field test was performed in January 1993 on an abandoned gas-producing well with a BHT of about 130°C, an average matrix permeability of 0.01 μm 2 and a produced brine salinity of more than 300 g/l TDS. The second test was performed in a well from a gas storage field with a temperature of about 87°C, an average permeability of 0.06 μm 2 and a produced brine salinity of more than 270 g/l. Based on the information provided from the first field test and the feasibility study performed for this well, a lower molecular weight partially sulfonated acrylamide terpolymer was finally used for this test. Using a cationic acrylamide copolymer, the third field test was performed in a low-temperature, high-brine-salinity gas storage well with BHT of 30°C and brine salinity of 218 g/l. Based on the excellent results of the third field test, the same polymer was selected for the last water shut-off treatment in a low-temperature gas storage well with a matrix permeability ranging from 0.04 to 3.6 μm 2. Since the treatment, the gas well and the gas storage wells have exhibited improved production performances.

00/01269 Hydraulic fracture design and optimization of gas storage wells

00/01269 Hydraulic fracture design and optimization of gas storage wells

Hydraulic fracture design and optimization of gas storage wells

Conventional hydraulic fracture design and optimization involves the use of two- or three-dimensional hydraulic fracture simulators. These simulators need a wealth of reservoir data as input to provide users with useable results. In many cases, such data are not available or very expensive to acquire. This paper provides a new methodology that can be used in cases where detail reservoir data are not available or prohibitively expensive to acquire. Through the use of two virtual intelligence techniques, namely neural networks and genetic algorithms, hydraulic fracture treatments are designed using only the available data. The unique design optimization method presented here is a logical continuation of the study that was presented in two previous papers [McVey et al., 1996. Identification of parameters influencing the response of gas storage wells to hydraulic fracturing with the aid of a neural network. SPE Computer Applications Journal, Apr., 54–57; Mohaghegh et al., 1996b. Predicting well stimulation results in a gas storage field in the absence of reservoir data, using neural networks. SPE Reservoir Engineering Journal, Nov., 54–57.]. A quick review of these papers is included here. This method will use the available data on each well, which includes basic well information, production history and results of previous frac job treatments, and provides engineer with a detail optimum hydraulic fracture design unique to each well. The expected post-hydraulic fracture deliverability for the designed treatment is also provided to assist engineers in estimating incremental increase in recovery to be used in economic calculations. There are no simulated data throughout this study and all data used for development and verification of all methods are actual field data.

Foamed Acid Removes Formation Damage in High-Volume Gas-Storage Wells

This article is a synopsis of paper SPE 51037, "Deliverability Enhancement of High-Volume Oriskany Gas-Storage Wells Using Foamed Acid as a Damage-Removal Medium," by J.S. Fontaine Jr., SPE, Universal Well Services Inc., and S.G. Rouze, SPE, Williams Gas Pipeline-Transco originally presented at the 1998 SPE Eastern Regional Meeting, Pittsburgh, Pennsylvania, 9-11 November 1.

Identification of Parameters Influencing the Response of Gas Storage Wells to Hydraulic Fracturing With the Aid of a Neural Network

SummaryPerforming hydraulic fractures on gas storage wells to improve their deliverability is a common practice in the eastern part of the U.S. Most fields used for storage in this region are old, and the reservoir characteristic data necessary for most reservoir studies and hydraulic fracture design and evaluation are scarce. This paper introduces a new method by which parameters that influence the response of gas storage wells to hydraulic fracturing may be identified in the absence of sufficient reservoir data. Control and manipulation of these parameters, once identified correctly, could enhance the outcome of frac jobs in gas storage fields. We conducted the study on a gas storage field in the Clinton formation of northeastern Ohio. We found that well-performance indicators before a hydraulic fracture play an important role in how good the well will respond to a new frac job. We also identified several other important factors.The identification of controlling parameters serves as a foundation for improved frac job design in the fields where adequate engineering data are not available. Another application of this type of study could be the enhancement of selection criteria among the candidate wells for hydraulic fracturing. To achieve the objective of this study, we designed, trained, and applied an artificial neural network. The paper will discuss the results of the incorporation of this new technology in hydraulic fracture design and evaluation.

Spindletop salt-cavern points way for future natural-gas storage: S. A. Shotts, J. R. Neal, R. J. Solis & C. Oldham, Oil & Gas Journal, 92(37), 1994, pp 68–75

Spindletop underground natural-gas storage complex began operating in 1993, providing 1.7 bcf of working-gas capacity in its first cavern. The cavern and related facilities exemplify the importance and advantages of natural-gas storage in leached salt caverns. Development of a second cavern, along with continued leaching of the initial cavern, target 5 bcf of available working-gas capacity in both caverns by the end of this year. The facilities that currently make up the Spindletop complex include two salt dome gas-storage wells and a 24,000-hp compression and dehydration facility owned by Sabine Gas; two salt dome gas-storage wells and a 15,900-hp compression and dehydration facility owned by Centana; a 7,000-hp leaching plant; and three jointly owned brine-disposal wells. The paper discusses the development of the storage facility, design goals, leaching plant and wells, piping and compressors, dehydration and heaters, control systems, safety and monitoring, construction, first years operation, and customer base.

Proper bit design improves penetration rate in abrasive horizontal wells : Gentger, R J Oil Gas JV91, N32, Aug 1993, P39–42

Overall drilling penetration rates nearly tripled, and drill bit life nearly doubled compared to conventional bits when specially designed natural diamond and polycrystalline diamond compact (PDC) bits were used during a seven-well horizontal drilling program. The improvement in drilling performance from better-designed bits lowered drilling costs at ANR Pipeline Co.'s Reed City gas storage field in Michigan. Laboratory tests with scaled down bits used on abrasive cores helped determine the optimum design for drilling the gas storage wells. The laboratory test results and actual field data were used to develop a matrix-body natural diamond bit, which was later modified to become a matrix-body, blade-type polycrystalline diamond compact bit. This bit had excellent penetration rates and abrasion resistance. The paper describes the background to the project, bit selection, natural diamond bits, field results, new bit designs, and field results from the new design.

Cement Bonding Characteristics in Gas Wells

Summary A program was performed to study the effects of cyclic pressure/temperature fluctuations of gas storage wells on annular leakage. A review of pertinent literature was conducted, and operators of gas storage wells were surveyed to determine their experience in the area. Results indicated that for most of the gas storage wells currently in operation. Surface leakage is not a problem. Where leakage is reported, cyclic fluctuations do not appear to be a significant cause. In the majority of cases, leakage occurs within the first few cycles, indicating that it is caused more by static then by dynamic loads. The only variables found to correlate with leakage at a high level of significance were depth and bottomhole pressure (BHP). Wells that leaked tended to be deeper and had higher pressures than those that did not. The only way to stop leakage effectively at these higher pressures is the use of mechanical sealing mechanisms. Introduction and Background Gas intrusion into cemented wellbores and the resultant leakage to either the surface or porous formation below the wellhead have been persistent problems in the gas industry for many years. These problems have resulted in significant safety hazards and economic loss to operators. Through the efforts of a number of researchers in the past 2 decades, cementing techniques in general have been vastly improved and have helped reduce the magnitude of the problem. Little work has been done, however, to determine the effects of pressure/temperature cycling on the bonding characteristics of annular cement to casing. Data of this type are of particular importance to operators of gas storage wells because these wells operate on periodic injection/withdrawal cycles with associated pressure/temperature fluctuations. The current project was initiated in an effort to begin study of this problem. It was conducted in two phases. First, available literature was reviewed to identify previous work in cementing technology in general and in the area of annular leakage of oil and gas wells in particular. Then, operators of gas storage wells were surveyed to determine the magnitude of the annular leakage problem, to identify similarities or differences in wells with known annular leakage, and to establish typical environmental/operating parameters of gas storage wells. Literature Review A computerized search of the open literature was conducted by use of the COMPENDEX data base (Dialog Information Services Inc.). From this search, 24 references were selected for more detailed review. These works were thought to describe fairly well the general evolution of thought from the early 1960's until the present on the causes and means of prevention of gas leakage (also called gas migration and annular gas flow) in cemented wellbores.1–24 A more detailed review of the papers than given here can be found in Ref. 25. Past research efforts can be divided into two broad categories: methods and materials designed to minimize the leakage of formation pressures through the cement itself (i.e., the percolation of gas into the cement during setting and curing and the resultant creation of leakage paths) and methods designed to prevent gas migration at the cement/casing and cement/formation interfaces. Some researchers categorized these as two separate failure mechanisms, while others categorized them as separate cases of a single mechanism. In either case, it is evident that means taken to prevent the formation of leakage paths through the cement itself will also help prevent the formation of leakage paths at the interfaces. Additional preventive measures may be necessary, however, to minimize or to prevent leakage at the interfaces. Most research has concentrated on the prevention of leakage through the cement column itself, and one fairly well developed theory explains the need for prevention of these types of failures. This theory states that annular gas flow is caused by a hydrostatic pressure loss sometime between placement of the slurry in the wellbore and the development of sufficient static gel strength to resist the percolation of gas into it.24 Static gel strength is that internally developed rigidity in the slurry that resists a force placed on it. The gelling process will begin immediately after pumping has stopped and will continue until the cement develops a set. As gel strength increases, the cement column begins partially to support itself and its volume decreases owing to loss of filtrate to the formations and/or to hydration. Hydrostatic pressure caused by the slurry column lessens as the column begins increasingly to support itself and as volume changes occur. If volume changes are large enough and if the gel strength is not yet sufficient to resist gas intrusion, leakage to other producing zones or to the surface (directly or through a "leap-frog" approach from zone to zone) may occur.

Oil and Gas Developments in Eastern Canada in 1988

Exploration activity on Canada's east coast offshore region continued at a steady rate in 1988. A total of 10 wells were active: 1 exploratory well offshore Nova Scotia, and 5 exploratory wells and 4 delineation wells offshore Newfoundland. The highlights of 1988 were Mobil's discovery of a new gas and condensate pool south of Sable Island offshore Nova Scotia, and successful delineation drilling results offshore Newfoundland by Petro-Canada at Terra Nova and by Husky Oil Operations at Whiterose. Based on these successes, the estimates of discovered oil and gas resources for the region have been revised upwards to 235 million m3 (1.5 billion bbl) of oil and condensate and 309.4 billion m3 (10.9 tcf) of natural gas. A significant step was made toward development of the Hibernia oil and gas field with the signing of a Statement of Principles by the governments of Canada and of Newfoundland and Labrador with Mobil Oil Canada and its partners. Also Petro-Canada is undertaking a preliminary engineering study to evaluate alternative development scenarios for Terra Nova field. Studies are also in progress on possible schemes to develop the several natural gas discoveries and the 2 small oil discoveries in the Nova Scotia offshore. Legislation required to implement joint federal-provincial resource management offshore Nova Scotia has been passed by the Canadian Parliament and the provincial legislature and will likely be proclaimed in 1989. At that point, a new resource management board will assume responsibility for the Nova Scotia offshore. This arrangement is identical to that established in the Newfoundland offshore in 1987. The future looks bright for the East Coast given the stable resource management regime, the regular schedule of rights issuances, and the large remaining potential. Steps to development of the best of the discoveries will lead to an increase in the pace of exploration in the early 1990s. Activity in Ontario in 1988 was at its highest level since 1980, with drilling completed at a total of 188 wells for an aggregate length of nearly 107,000 m (350,000 ft). Activity was paced by a record amount of drilling of Ordovician targets, as interest in this very successful play continued to increase. Drilling of Ordovician targets was reported to be complete at 25 exploratory wells, 15 development wells, and 2 stratigraphic tests, resulting in 21 new oil producers and 4 gas producers. Oil production in Ontario increased dramatically in 1988, due entirely to production from new Ordovician reservoirs discovered since 1983. Production totaled approximately 190,570 m3 (1.2 million bbl) compared to 135,635 m3 (853,000 bbl) in 1987. Further production increases a e expected in 1989. Activity in Quebec in 1988 was concentrated in the Basse-Terres region near Trois Rivieres in the St. Lawrence lowlands, and on Anticosti Island. Five exploratory wells and 6 natural gas storage wells were drilled. Two of the exploratory wells resulted in discovery of an accumulation of natural gas in unconsolidated glacial sediments beneath Lake St. Pierre on the St. Lawrence River. There was no drilling activity in onshore portions of Prince Edward Island, Nova Scotia, New Brunswick, or Newfoundland in 1988.