Field Development Wells Research Articles

Real-time porosity prediction using gas-while-drilling data and machine learning with reservoir associated gas: Case study for Hassi Messaoud field, Algeria

A novel inverse intelligent model is developed to predict porosity in real time while drilling. It applies established machine learning (ML) models to gas-while-drilling (GWD) data calibrated with core porosity measurements for a saturated oil reservoir. The data are associated with the Cambro-Ordovician sandstone reservoir in the giant Hassi Messaoud oil and associated gas field, located in central-eastern Algeria. The ML methods applied to the input dataset of nine variables recorded while drilling are, extreme learning machine (ELM), support vector regression (SVR), random forest regression (RFR), multilayer perceptron neural network (MLPNN), and generalized regression neural network (GRNN) and their results compared with a suite of statistical prediction accuracy performance metrics: correlation coefficient (R), Nash-Sutcliffe efficiency coefficient (NSE), the root mean square error (RMSE), and the mean absolute error (MAE). The ELM model was found to deliver the highest accuracy in predicting real-time porosity for the validation data records (R∼0.929, NSE∼0.865, RMSE∼3.325%; MAE∼ 2.595%). The method and results identify a rapid and accurate new approach to the real-time prediction of rock porosity with only GWD data. The GWD input variables are typically available in every field well drilled at a much lower cost than running measurement while drilling (MWD) or wireline logging tool traditional used to provide porosity information. Each of the evaluated ML models could be easily integrated with real-time monitoring systems as wells are drilled. By doing so, substantial time saving and economic savings could be achieved in comparison with the extensive laboratory measurements and MWD/wireline tools that currently required to assesses reservoir porosity in field development wells. The method also provides petroleum engineers with real-time “quick look” porosity information during drilling that can contribute to safe real-time decision making. The method has potential for gas and oil reservoir evaluations.

A methodology for the optimal design of gathering pipeline system in old oilfield during its phased development process

In the later period of oil field development, new blocks or filled-in wells would be added to enhance the production capacity during the phased development process and thus some abandoned manifolds, wells and pipelines would be recycled. Hence, a practical and economic scheme to optimize the improvement of pipeline network is necessary. A model aiming at optimization of improved pipeline network layout is proposed considering the newly-tied-in wells, the newly-constructed pipelines, and the newly-developed blocks including wells and metering manifolds. The reliability of the pipeline network and the recycling of the occupied old manifolds and pipelines are also taking into account. Implementing the construction cost and the reliability as objective functions, the models seek to define: the number, location, and capacities of newly-developed manifolds; the affiliation of wells; the number of recycled manifolds, wells, and pipelines; the interconnection between all the workable wells and manifolds. This model is solved by the simulated annealing genetic hybrid algorithm. Two real cases based on two oil fields are given in detail, which includes the optimized topological structure of the pipeline network layout, corresponding pipeline parameters, overall investment and the reliability of the optimized pipeline network. Meanwhile, the sensitivity factors including reliability, investment, upper metering limits of the manifolds are analyzed. In conclusion, the manifolds governing few wells are recycled and new manifolds are set up in the new block. The specifications of new pipelines, phased development costs, and the reliability of the optimized pipeline network are obtained. Thus, this research is able to estimate the investment and reliability when improving the pipeline network and to provide guidance for the management of the whole phased development process of old oilfields.

Perforation and Flowback Highlights From the Gorgon Field, Offshore Australia

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 182420, “Perforation and Rig Flowback Highlights for the Gorgon Field Development Wells,” by A.K. Morrison, SPE, and J.P. Beinke, SPE, Chevron Australia, prepared for the 2016 SPE Asia Pacific Oil and Gas Conference and Exhibition, Perth, Australia, 25–27 October. The paper has not been peer reviewed. The Gorgon liquefied-natural-gas project (Fig. 1) is one of the world’s largest natural gas projects and the biggest single resource development in Australia’s history. In 2014, eight Gorgon wells were perforated successfully, intercepting between three and seven commingled zones and gross intervals of up to 500 m per well. This paper contrasts the detailed perforating and flowback plan with the results of the operation where a number of planned, and some unplanned, contingencies were faced. Perforation Basis of Design The main element of the Gorgon- project well design that affected perforating was that reservoir sections would be completed with a cemented 70-in. liner in 8¾-in. open hole, with the top perforation approximately 250 m below the liner top. Each well was to be completed in multiple formation zones, with the average gross perforation interval per well (top to bottom shot measured distance) expected to be more than 400 m and an average net perforation interval (sum of perforated zones) of close to 150 m. Four perforating alternatives were evaluated with respect to their relative operational and subsurface risks: Tubing-conveyed perforating (TCP) shoot and drop—guns deployed into the liner on a gun hanger before upper completion is run and then fired and dropped after perforation TCP shoot and pull—a separate drillpipe-conveyed perforation trip before completion with use of a sized kill pill after perforation to mitigate losses before the upper completion is run Coiled-tubing conveyed Wireline conveyed After analysis, the TCP shoot-and- drop option was eliminated because of the additional time and well-control risk of drilling the required rathole to accommodate dropped guns. Shoot and pull was not considered a viable option because of a lack of a temperature-rated, post-perforation kill pill. Coiled tubing was rated feasible but with inherently greater operational risks when performed from a mobile offshore drilling unit. The process concluded that the wireline-conveyed method was the best solution despite requiring several perforating runs per well. Operational issues associated with this technique were identified, and plans were developed for these to be managed safely. The gun length per trip was expected to be approximately 30 m, necessitating at least five wireline trips to perforate each well, with each run expected to take between one and two rig shifts. In the event of failure (e.g., unsuccessful cable development), the selected contingency method for deployment was coiled tubing, which was considered a proven alternative.

Planning of the industrial and hydrogeological research at the final stage of hydrocarbon deposits development

Formulation of the problem. The article focuses on monitoring the wells operation at the final stages of hydrocarbon deposits development. It is known that at the final stages of the field development wells operation is characterized by a number of complications associated with the depletion of the reservoir energy and flooding with stratal waters. According to the program "20/20" gas production in JSC "Ukrgasvydobuvannia " is expected to increase to 20 billion m3 per year. One way to achieve this goal is to intensify the production on the operating fields. Consequently, flooding of the wells is likely to aggravate. However, there has been a mismatch between quantitative and qualitative indicators of industrial and hydrogeological studies of the wells. Control measurements of the water factor at the wellhead do not fix the fluid flow, and the samples selected by the field geological service are reservoir water.The purpose of the article. To determine the causes of the indicated differences in the conditions of wells operation and the results of industrial and hydrogeological research in Yuliyivske field in 2016. Methods. The author s own achievements as well as the research results of domestic and foreign investigators made the methodical basis for the article.Results. In 2016 we operated wells No. 57, 61, 73, 77 without the signs of water flooding in Yuliyivske field. Well No.7 began flooding from April, and by the end of the year it had acquired an intensive character. Analysis of the opearational water usage of well No.50 showed that it began flooding. The degree of water flooding is found to be not heavy, further increase in the flow rate of formation water is not expected. The data, especially industrial ones (gas flow rate and water factor) suggest possible start of wells No. 60 and 63 flooding. In 2017 they will be the priority for industrial and hydrogeological studies. Wells No. 56 and 83 are operating in the field conditions of non-intensive income and outcome of stratal waters. Scientific novelty and practical significance. It has been found out that among the twelve wells which were controlled on water flooding, only two meet the conditions of passing liquid to the surface. Considering this fact, it has been proposed to divide field wells into two groups before the beginning of industrial and hydrogeological studies. In the first group it is advisable to carry out hydrogeochemical control of associated water composition only. The second group includes the wells where it is appropriate to carry out control measurements of water factor in the estuary.

Real-Time Image Data Aids Horizontal Drilling in Carbonate Reservoirs Onshore Abu Dhabi

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 101916, "Real-Time Image Data for Successful Horizontal Drilling in Carbonate Reservoirs Onshore Abu Dhabi, UAE," by Maria Teresa Ribeiro, Mohamed Al Neaimi, Irfan Hendrawan, Sultan Karrani, Mohamed Ben Saad, Mohammed R. Ayoub, Kamal Zubair, Khalid Al Marzouqui, and Suaad Khoori, Adco, prepared for the 2006 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 5–8 November. Real-time image interpretation was used during an intensive horizontal-well drilling campaign in two major carbonate fields onshore Abu Dhabi. Major and smaller faults were identified by use of sophisticated methods for interpreting seismic data. These faults were confirmed with image logs while drilling the horizontal field-development wells. Real-time image-data interpretation enabled geosteering decisions while drilling into reservoirs with complex structure or unknown geology or in areas with sparse geological or structural information. Introduction The success of drilling horizontal wells depends on accurate placement of the wellbore in the reservoir. Generally, placement is based on offset-well information, seismic data, and geological models. Although seismic data provide continuous coverage, the resolution is poor, and velocity errors may lead to wrong depths at planned well locations. As more wells are drilled, additional detailed measurements are acquired, including formation dip and acoustic velocity, and the reservoir geometry is refined. Dip data can be used to recognize structures such as folds and faults and to aid the interpretation of the depositional environment. Depth uncertainty related to survey measurements could lead to structural uncertain-ty, especially for highly deviated wells. The presence of unexpected subseismic faults can cause problems with correct well placement while drilling. Logging-while-drilling (LWD) real-time azimuthal resistivity and density images can be used for accurate estimation of dip and strike of the intersected formations. Structural heterogeneities, such as faults, can be detected and immediate actions taken while geosteering the well. This action is particularly important for horizontal wells in thin reservoirs, in structurally complex geology, or in an area where structure is not calibrated because of sparse control points. In such situations, the use of image data while drilling the well can help drilling of a good well in terms of well placement and accessibility. Real-Time Imaging Technology LWD technology uses the rotation of bottomhole-assembly sensors to scan around the interior surface of a borehole. Technologies to acquire images of formation gamma ray, density, photoelectric factor, and resistivity are available. The amplitude of an image sinusoid gives quantitative information on the relative dip and azimuth between the borehole and the formation layer. Most LWD images are oriented relative to the top of the borehole (generally, these images are acquired in high-angle wells). If the borehole is perpendicular to the layering, the amplitude of the sinusoid is low. With increasing relative angle, the amplitude of the sinusoid increases until the borehole is parallel to the formation and the layering appears as lines running down the image. Generally, the sinusoid magnitude on the image gives sufficient information while drilling to aid well geosteering. Measurement-while-drilling data are used to derive true formation dip and azimuth, helping update the reservoir-structure information.

Ness Horizontal-Well Case Study

Summary This paper reviews the reservoir management work that led to the recommendation to drill the Ness field horizontal well. It also discusses the poor well performance seen almost immediately after production began and the reasons for that well performance revealed by a postdrill reservoir simulation. Finally, the atypical logging responses observed in the well are discussed. Introduction The Ness field has contributed significantly to the oil production volumes and revenue for the partners in the Mobil-operated Block 9/13 in the U.K. sector of the North Sea. When the horizontal well was drilled, the partners were Amerada Hess, Enterprise Oil, North Sea Holdings, and Mobil. The field was originally brought on stream in Aug. 1987 at a rate of 17,500 BOPD [2780 m3/d oil]. At the end of 1988, production rates began to decrease because of water production, which was thought to be caused by water coning. by Summer 1989, it was apparent that additional production wells had to be drilled to maintain a plateau production rate. Alternatively, the partnership would have to accept an extended production life associated with increasing water production rates production life associated with increasing water production rates and lower ultimate recovery. The initial field development wells were drilled and completed with vertical-well technology. Both vertical and horizontal wells were considered for the additional wells. In particular, the expected performances of both well types were particular, the expected performances of both well types were compared on the basis of their impact on the long-term development program for Ness. program for Ness. This paper addresses the reservoir management questions raised and decisions made that led to the recommendation to drill the Ness horizontal well. Further, explanations are offered for the causes of the unusual logging-tool responses seen in horizontal wells, specifically from measurement-while-drilling (MWD) technology. Background Discovery and Geologic Description. The Ness field was discovered in May 1986 by the Exploration Well 9/13b-28A (S28A), which encountered 152 ft [46.3 m] of hydrocarbon-bearing Beryl formation sandstone. It was later completed as a development well. A second development well, Well 9/13b-31Z (S31Z), was completed in Aug. 1987 and had 106 ft [32.3 m] of Beryl formation pay. Figs. 1 and 2 show the field and wells, respectively.

Reservoir Zonation in Silurian-Devonian Carbonates of Wells Field, Dawson County, Texas

Wells field in Dawson County, Texas, has produced over 7.5 million bbl since 1955 from Silurian-Devonian carbonates. Although originally classified as a Devonian field, production there actually is out of the Silurian Wristen and Fusselman formations. Wells field is an extremely complex system of structured and stratigraphic reservoirs not easily characterized by traditional subsurface mapping techniques. Detailed lithologic analyses of well cuttings from 29 wells in and around this field were done to evaluate reservoir zonation and potentials for either new field development wells, or recompletions from existing well bores. These analyses have shown that paleotopographic highs on the Fusselman unconformity across the field created optimum sites for Fusselman dolomite reservoir development, and collateral development of Wristen reservoirs. The Wristen reservoirs are in the form of porous carbonate mounds that grew adjacent to the paleotopographically high areas, or simple compactionally fractured cherty carbonates over these highs. The recognition of Fusselman paleotopography in most wells is implied by thickness and facies changes in the overlying Wristen section. A certain amount of structure and facies-induced reservoir separation has been documented. The results of this study have been used to identify several areas of the field where each of the three reservoirs couldmore » be exploited for underdeveloped reserves.« less

The Cyrus Field, Block 16/28, UK North Sea

Abstract The Cyrus Oilfield is located in Block 16/28 of the UK sector of the North Sea approximately 250 km (155 miles) NE of Aberdeen and 55 km (34 miles) NE of the Forties Field. The trap consists of a broad, very low relief four-way dip closure developed over a deeper tilted fault block. The reservoir consists of submarine-fan sandstones of late Palaeocene age, belonging to the Andrew Formation. Provenance was to the NW resulting from the early Tertiary sea-level fall which exposed the East Shetland Platform. The reservoir has been sub-divided into two zones, an upper zone of interbedded sandstones and mudstones with net to gross ratios of 0.4 to 0.6 and sandstone porositites of 12% to 18%, and a lower zone of massive fine-grained sandstones plus subordinate thin shales and limestones, with net to gross ratios in excess of 0.9 and porosities averaging 20%. The reservoir is filled with undersaturated oil of 35° API and is normally pressured. The estimate of initial oil-in-place is 75 MMBBL. Development of the field is centred on the use of BP's SWOPS (Single Well Offshore Production System) vessel using two horizontal field development wells which feed into a single seabed template for offtake. Ultimate recovery from the field is estimated to be approximately 12 MMBBL.

Semisubmersible Drilling Tender Unit

Summary The offshore industry has shown significant interest in deepwater production in the Gulf of Mexico, as evidenced by the large number of deepwater leases. This paper addresses an innovative method to control cost of field-development wells on deepwater leases. Drilling tender rigs have been economically attractive in shallow water depths. The limitations experienced by conventional tenders in deep water with regard to mooring and motions in a seaway can be overcome by use of a semisubmersible tender.

Dipmeter Validity in Deviated Bore Holes: ABSTRACT

Usually, offshore field development wells will be drilled as highly deviated bore holes and evaluated by a series of logs including dipmeters. Dipmeters run in a deviated bore hole have often been treated with the same respect for validity of accuracy as any regular dipmeter run in a practically vertical bore hole. However, when the formations exhibit small dip magnitudes (from the horizontal) and are penetrated by rather highly deviated bore holes, accuracy of the dipmeter results should be held suspect. Recent work has indicated any small error in any one of several instrument measured parameters can result in an error in the final dipmeter results such that the formation dip magnitude will be erroneous and even the dip direction can be wrong. Errors in relative bearing and bore-hole diameters (including caliper accuracy and pad depth of investigation) are the most susceptible to causing errors in the final computed results. This could have serious consequences in that erroneous dip vectors would be displayed as valid dip vectors. Unfortunately it is almost impossible, even for an expert, to visibly determine that wrong dipmeter vectors have been plotted as the result of poor input data. Several actual and theoretical dipmeter computation results will be presented wherein a controlled amount of error will be deliberately introduced to show its effect upon the computed dip vectors. Results of these computations indicate that to give consistently good dipmeter results under most conditions encountered in highly deviated bore holes, practically all of the instrumentation must perform at accuracy levels considerably in excess of current instrument capabilities to yield results of the same quality as those obtained in nearly vertical bore holes. End_of_Article - Last_Page 707------------

TUBINGLESS COMPLETIONS IN THE SURAT BASIN

Oilfield operators have always looked for ways of reducing the costs of oil and gas development projects and especially when investment costs were critical to project economics. Tubingless completions have evolved over the last 30 years in North America to fill the need for reduced investment costs particularly in the case of fields with either limited reserves or limited profitability.Tubingless completions basically utilise small diameter tubulars to function as both production casing and flowstring. The tubulars are cemented in the borehole, not to be removed or recovered until the field is depleted and/or the well abandoned. The technique is limited in application to those fields with no corrosion or wax or hydrate problems and with a limited requirement for reservoir stimulation and workovers. The greater the number of operations performed within the tubingless well bore the greater the risk of losing the well.The main benefits of tubingless completions are as follows:Reduction in development well completion costs.Marginally productive hydrocarbon zones can be completed and tested.Completion of individual gas zones of multi-pay wells within their own permanently segregated flowstrings at much lower capital and operating costs.The experience this far with Kincora gas field development wells indicates the tubingless completion method to be completely feasible for gas wells drilled in the Surat Basin and possibly in other areas of Australia.

Oil and Gas Developments in North Mid-Continent in 1971

Crude oil production in Kansas (78,532,200 bbl), and natural gas production (894,450,803 Mcf) declined in 1971. Production of helium (2,905,503 Mcf) and natural gasoline and natural gas liquids (28,652,786 bbl) increased. LPG production now equals 36% in quantity of that of crude oil produced in Kansas. Drilling was 2% less than in 1970, with 2,413 wells reported. In Nebraska, 51.6% of the 80 field development wells and 5.8% of the 103 exploratory tests were successful. Cheyenne County had a significant channel sandstone oil-field discovery. Increased drilling activity is indicated for 1972. Drilling for oil and gas in Iowa and Missouri was slow in 1971. In Minnesota it was confined to tests drilled by gas storage companies. About 8,000 holes were drilled for water in Wis onsin, during 1971, with no shows of oil or gas reported.

Oil and Gas Developments in New York State in 1971

Natural gas production in New York State declined in 1971. Leasing activity increased because of 2 new Edgecliff reef field discoveries. Only 3 oil field development wells were drilled.

Oil and Gas Developments in New York State and New England During 1970

Natural gas production in New York State declined in 1970. Of 15 Silurian tests, 12 were gas, and 4 of 11 Devonian tests were gas wells. Seventy-six oil field development wells were drilled. There was no activity in New England.

REVIEW OF AUSTRALIAN PETROLEUM EXPLORATION, 1967

In Australia, 1967 can aptly be termed the year of the impending energy revolution. The long-awaited upturn in the rate of oil and gas discovery eventuated and was successfully associated with a decided swing to concentration of effort on the continental shelf.Natural gas has dominated the discovery scene to such an extent that if experience in Western Europe is taken as a guide line, natural gas can be expected to supply 20 per cent of the local energy market within the next decade. This is expected to be accomplished primarily at the expense of oil, to a lesser extent of black coal and finally of brown coal. Natural gas will erode only the growth rate of these latter fuels.Natural gas will arrive in about March, 1969, at Melbourne, Brisbane, and Adelaide from the Barracouta, Roma and Gidgealpa-Moomba fields respectively. Gas reserves at Gilmore, Mereenie and Dongara remained undeveloped due principally to market difficulties. Recently a discovery has been made in the Gulf of Papua.Crude oil production from the Moonie-Alton fields increased to more than 8,750 b.p.d. during the year, and deliveries commenced from Barrow Island with production rising to 25,000 b.p.d. by the end of the year. The Marlin, Kingfish and Halibut fields in Bass Strait are expected to be in production by mid-1969.The heavy swing of exploration interest to the continental shelf was probably the most significant feature in the year's search pattern. The remarkable rate of success in the offshore Gippsland Basin was the major factor, but the Barrow-Pasco Island success strengthened this trend. The availability for the first time in Australia of a number of offshore drilling rigs, supported by greatly improved techniques in marine exploration, led to the explosion of interest in this exciting sphere. Despite this, exploration and development costs are considerably less on land, and many major basins remain very poorly explored. Important discoveries in onshore basins must be expected in the future.The passage of new offshore legislation will markedly influence future patterns of exploration. The extent to which this will result in diversification of exploration interest remains to be seen.Oil well statistics on footage drilled indicate an increase of about 43 per cent over the 1966 total, bringing the total footage figure to just over one million feet. Closer examination of these figures, however, discloses a disquieting drop in new exploration footage at the expense of field development wells. Moreover, offshore wells are being drilled to greater total depths. Of 274 wells drilled in 1967, 187 were developmental and 87 exploratory. This compares with 134 wells in 1966 of which 97 were exploratory.In conclusion it would appear that the events of 1967 have pointed to Australia becoming self-sufficient in oil by the mid-1970s, providing present discovery rates are maintained. By that time natural gas is expected to be supplying 20 per cent of the total energy requirements. All of which highlights the probability that 1968 will see the Federal Government looking far more closely at the long-term pricing of Australian crude and the eventual review of incentive formulas.

Gas and Oil Developments in New York State, 1964

In 1964, drilling activities for natural gas increased from 1963, but gas production decreased by 18 per cent. Thirteen wells were completed to the Oriskany, and one to the Onondaga. Forty-four wells were drilled to the Medina-Queenston-Clinton gas sands. Sixteen wells tested formations below the Queenston. There were 157 oil field development wells drilled in 1964. Oil production increased almost 12 per cent from 1963.

Developments in Arizona and Western New Mexico in 1962

Exploratory and development drilling decreased 12%, from 799 wells in 1961 to 701 wells in 1962. Ninety-nine new-field wildcats were drilled, resulting in 6 discoveries. This is an increase in wildcat drilling of 39% over 1961 when 71 wildcats were drilled and 14% were successful. The majority of both exploratory and field development wells were drilled in the San Juan basin where proved reserves of oil and gas provide an incentive for exploratory drilling by smaller operators and dependents. Kerr-McGee He extraction plant has provided incentive for increased exploration activity in Arizona. Geophysical activity decreased in both New Mexico and Arizona.

Developments in Indiana in 1961

Indiana's oil production for 1961 totaled an estimated 11,460,000 bbls., a decrease of approximately 594,000 bbls., or 5% from the 1960 production. The total number of wells drilled decreased from 1,072 in 1960 to 788 in 1961, a drop of nearly 27%. Of the 788 total wells drilled, 246 were wildcat wells and 542 were field-development wells. Thirty of the wildcat wells were successful, 12 being completed as new pools, 10 as extensions to pools, and 8 as new pays in productive areas. Twenty-four successful wildcat wells were completed in rocks of the Mississippian System, 2 in the Devonian, and 4 in the Ordovician. Pennsylvanian and Mississippian formations of southwestern Indiana continued to be the principal objectives of exploratory drilling. Successes in Chester reservoirs in southeastern Pike County were significant. These successes indicate that the area of shallow Chester reservoirs throughout eastern Pike County, southern Daviess County, and Dubois County is worthy of further exploration. Exploration for underground gas storage sites continued during 1961. Stratigraphic units tested include Devonian, Silurian, Trenton, and Knox strata.

Developments in Indiana in 1960

Oil production in Indiana totaled 12,054,000 bbls. during 1960; this figure represents an increase of 4.1% over the 1959 production of 11,554,000 bbls. During 1960, there were 1,072 wells drilled, an increase of 18.0% over the 910 wells drilled in 1959. Of this total, 394 were wildcat wells and 678 were field-development wells. Thirty-four of the wildcat wells were successful: 15 were new pools, 17 extensions to pools, and 2 new pay zones in productive areas. Twenty-six of these wells were completed in rocks of the Mississippian system, 4 in the Pennsylvanian, 1 in the Devonian, and 3 in the Ordovician. Most of the wells drilled during the year were in the southwestern counties of the state and were drilled to test reservoirs in rocks of the Chester series. Approximately 44% of the exploratory effort of 1960 took place in Spencer County alone. Interest in the possibility of deeper production was evidenced by the drilling of several sub-Trenton tests in the state during the year.

Developments in Upper Gulf Coast of Texas in 1959

This report covers the Upper Gulf Coast of Texas, located in the southeastern corner of the state and the adjacent Continental Shelf. The area includes twenty-nine counties, comprising Texas Railroad Commission District No. 3. There was a marked decrease in exploratory drilling on shore, while exploratory drilling offshore showed a lesser decline over 1958. The total number of both exploratory and field development wells drilled was slightly greater than in 1958. Oil production again declined in 1959. The Texas state-wide number of producing days in 1959 dropped to an average of 9.25 producing days per month compared to an average of 10.16 producing days during 1958 and 14.25 producing days in 1957. Gas production showed a slight increase over 1958. In 1959, forty-four new oil and gas fields were discovered. As in 1958, most of the discoveries were along the deep Frio, Yegua, and Wilcox (Eocene) formational trends. On the Continental Shelf, five wildcats were drilled in 1959 versus six in 1958, resulting in the discovery of two new fields. Exploration and drilling during 1960 is expected to center, as in the past several years, along the Frio, Yegua, and Wilcox trends.