Drilling Campaign Research Articles

満洲における日本の石油探鉱

Japan hunted oil in Manchuria before World War II. In 1927 Japanese geologist found scattered asphalt in vugs of basalt and quaternary gravel deposits on the north western shore of Hulun Nur (lake), NW Manchuria. Geological Survey of China made a check survey of the area, and found the same asphalt in 1931.After establishment of Manchukuo, geological survey, tortion balance and refraction seismograph survey, and drilling were conducted during 1932-1941. One deep well (1,114 m TD) and 21 core holes were drilled on the northern shore of the lake, but no potential oil were found.That the core hole drilled in Fuxin coal mine hit oil shows in 1938, led to extensive oil exploration program. Geological field party mapped a broad anticline located on east of Fuxin, and the core hole drilled on the anticline recovered some 30 m thick sandstones (100-200 m in depth) impregnating with oil. To explore this oil called on massive drilling campaign, and 47 or more wells were drilled on this anticline, but the reservoir quality was not good enough to establish commercial production. It is noteworthy to point out that the geologists engaged in Fuxin oil exploration thought that the oil came from Jurassic shales deposited in fresh water lake.In 1940 oil shows were found in the water wells near Chengde, and a one-month field check survey was conducted, and mapped a small anticline in Jurassic shales, but no further exploration was conducted.

Predicting gas production from future gas discoveries in the Netherlands: quantity, location, timing, quality

Recent policy and market developments have raised the question not only as to how much gas remains to be discovered in the Netherlands but also where and when it will be produced and of what quality. These questions are addressed by compiling a ‘firm futures’ database, estimating the ‘potential futures in proven plays’ and simulating the exploration process using the prospect portfolio. The firm futures are assessed using an integrated play evaluation method in a combined database/GIS environment. The database includes a prospect portfolio of firm futures, well data and maps. Volumetric estimates (low, mean and high success volumes) are assigned to the prospects. The risk of each prospect is estimated using play maps and the historical success ratio for that play. Using standard GIS functionality, the distance to production nodes, the gas quality, licence status and operator are determined for each prospect. The prospect portfolio is not static but dynamic. Using the creaming curve, fractal distribution analysis and the average POS (Possibility of Success) of the play, the gas volume and the amount of structures in the potential futures category are estimated. Again, GIS functionality is used to determine possible new locations and the gas quality of the prospects. The prospect portfolio is the input for a computer program that stochastically simulates the exploration process. Assumptions about future drilling efforts, economic screening scenarios and time delays from discovery to production are made explicit. The program simulates annual drilling campaigns. A number of prospects are drilled according to an assumed exploration efficiency and the POS is used to determine the result: a discovery or a dry well. The discovered volume is economically assessed and, if economic, transformed into a production and gas-quality profile.

Deep-water plays of the Mauritanian continental margin

The coastal basin of Mauritania is emerging as a potential major petroleum province as a result of renewed exploration activity over the past five years. Two significant discoveries of oil and gas have been made at Chinguetti and Banda, proving that an effective petroleum system exists in this passive margin basin. The successful play type comprises Miocene turbidite channel reservoirs, sealed by fine-grained channel abandonment facies or a hemipelagic shale drape. The most prospective structures are associated with diapiric salt, although a variety of other structural styles, including compressional toe thrusts and rotated extensional fault blocks, are also present. The only source rocks proven to be effective in the immediate area occur in Cenomanian to Turonian deep-marine mudstones. However, regional evidence suggests that other intervals, including the Albian and the Paleocene, may also contain source facies. Future drilling campaigns by Woodside and other operators in the region will focus on realizing the value of existing discoveries through appraisal and tie-back exploration, while at the same time targeting new plays, particularly Late Cretaceous turbidites. Some of the major challenges to would-be petroleum explorers and producers in this basin centre around operating in a remote location almost totally lacking in infrastructure, and conducting activities in an environmentally responsible and sustainable manner.

中国における陸豊１３‐１海洋油田開発の紹介

Lufengl3-1 Oil Field is operated by JHN Oil Operating Company (JHN). It islocated about 250km the east south east of Hong Kong in a water depth of 145m and has beenproducing oil for about 10 years since October 1993. The current production rate is 12, 000 bopd.The field forms a dome shape anticline structure with gentle flanks and produces oil from highpermeable sandstone reservoirs with low gas oil ratio and strong bottom water drive.The 20th production well is drilled under the 5 th drilling campaign. Wells are developed fromstructurally high to flank positions with successive drilling campaigns. Horizontal wells (11 wellsout of all 19 wells) and Electrical Submergible Pumps (ESP) are adopted to maintain highproductivity and control water productionThe outline of the field and its development history are briefly reviewed and presented.

メタンハイドレートの資源化に向けた研究開発プロジェクトの現状について―掘削仕上技術課題は何か―

In order to increase the share of primary energy supplied by natural gas and to augment the supply of domestically produced natural gas, Japan became active in the R&D area of Methane Hydrate Resource in the mid-1990s. Under the leadership of the METI, the “Nankai Trough” METI Exploratory Test Well, the “Collaborative R&D Studies on Methane Hydrate” and the drilling experiment in the Mackenzie Delta were conducted. Based on the results of these efforts, the “Methane Hydrate Exploitation Program” was newly announced in 2001, with establishment of the “Research for Methane Hydrate Resources in Japan” project as a means of putting that program into force.The “Research for Methane Hydrate Resources in Japan” is being conducted by the “Research Consortium for Methane Hydrate Resources in Japan”an organization comprised of the Japan National Oil Corporation (JNOC), the National Institute of Advanced Industrial Science and Technology (AIST) and the Engineering Advancement Association of Japan (ENAA) and the Japanese Industry. Under this arrangement, JNOC conducts resource assessment R& D, AIST advances production method R&D, and ENAA handles environmental impact assessment R&D.Since then, the first round of onshore production testing in the Mackenzie Delta, Canada was implemented as the joint international collaborative research in 2002.In the beginning of 2004, comprehensive drilling campaign is planned to clarify the accumulations of the resources in the Nankai Trough offshore Japan. The second onshore production testing in Alaska is also under planning.These undertakings have gradually clarified the issues in the area of drilling and completion technology that we should face and handle for further exploration and future development. Top-hole drilling technology in the deep water, horizontal well drilling and completion technology in the unconsolidated formation, offshore production testing methods specific to methane hydrate development are the issues to be investigated.

Glaciers and Climate in the Andes between the Equator and 30° S: What is Recorded under Extreme Environmental Conditions?

Sublimation and melt disturb the environmental information obtained from ice core records in the Andes. In two case studies we demonstrate to what extent these post-depositional processes may remove major parts of the accumulated snow cover. Dark ash layers from the Tungurahua eruption changed the albedo of surface snow on Chimborazo glacier (6268 m, 1°30′ S,78°36′ W, Ecuador) between two ice core drilling campaigns and forced substantial melt. Re-distribution and washout of the chemical constituents shifted the concentration profiles obtained in December 1999 as compared to an equivalent core drilled in December 2000. The stable isotope records showed that approximately the water equivalent (weq) of an annual layer had melted, and that the percolating melt water penetrated within the firn layer to a depth of at least 16.5 m without refreezing. In the second example, from a site on the dry axis between the tropical and extra-tropical precipitation belts, significant loss of accumulated snow layers occurred by sublimation. A surface experiment at Cerro Tapado glacier (5536 m, 30°08′ S,69°55′ W, Chile) revealed that losses of ≈2 mm weq (≈5 mm snow) per day occurred during the dry period following the 1997/98 El Niño. This loss generally included the entire surface layer enriched in stable isotopes, and thus caused minimal disturbance of the isotopic signature (and hence climatic information) of the net accumulation, yet chemical constituents again experienced considerable changes in concentration. From annual layer counting and direct dating it is obvious that the major part of the accumulated ice on both glaciers is younger than 100 years; however, isotopic and chemical variations at least in the basal ice from Cerro Tapado clearly point to climate conditions different from the recent centuries. This evidence is supported by mass balance considerations derived from a glacier-climate model. The possibility of a third type of disturbance aside from sublimation and melting – in this case a significant hiatus in the environmental chronology – also deserves consideration for other icecore records from this region. Potential disruptions or discontinuities need to be carefully evaluated given the profound changes in climatic and glaciological conditions since the Last Glacial Maximum throughout Holocene times.

Champion East: Low-Cost Redevelopment of Shallow, Stacked, and Faulted Heavy-Oil Reservoirs

Summary The Champion East area offshore Brunei Darussalam consists of approximately 50 stacked, shallow, and intensely faulted heavy-oil reservoirs. These reservoirs have been under development since 1975 and have to date produced just 9% of the oil initially in place. Over the period 1998–2003, Brunei Shell Petroleum (BSP) is embarking on a major redevelopment with the aim of converting a further 30 million m3 of oil-in-place volume into commercial reserves. An overview will be given of how new technology is adding value to the total redevelopment, supported by actual application results and learning points. The primary development of Champion East is now nearing completion. The use of existing facilities and ultrashallow, long-reach horizontal wells—with innovative sand exclusion and down-hole intelligence—has achieved a 60% unit cost reduction over previous drilling campaigns in the area. The only way to unlock another 5 to 15% of the oil-in-place volume is to start secondary recovery through water injection, in combination with the use of electric submersible pumps (ESPs).

Weathering process at the natural fission reactor of Bangombé

The uranium deposits in the basin of Franceville (Gabon) host the only natural fission reactors known in the world. Unique geological conditions favoured a natural fission reaction 2 Ga ago. This was detected by anomalous isotopic compositions of uranium and rare earth elements (REE), which are produced by the fission reaction. In total, 16 reactor zones were found. Most of them are mined out. The reactor zone of Bangombe, is only 10–11 m below the surface. This site has been influenced by surface weathering processes. Six drill cores have been sampled at the site of the reactor zone of Bangombe during the course of the study and only one drill core (BAX 08) hit the core of the reactor. From these data and previous drilling campaigns, the reactor size is estimated to be 10 cm thick, 2–3 m wide and 4–6 m long. The migration of fission products can be traced by the anomalous isotope ratios of REE because of the fission process. The 149Sm/147Sm ratio close to the reactor zone is only 0.28 (normal: 0.92) because of the intense neutron capture of 149Sm and subsequent transmutation, whereas 147Sm is enriched by the fission reaction. Similar changes in isotopic patterns are detectable on other REE. The isotope ratios of Sm and Nd of whole rock and fracture samples surrounding the reactor indicate that fission-genic REE migrated only a few decimetres above and mainly below the reactor zone. Organic matter (bitumen) seems to act as a trap for fission-genic REE. Additional REE-patterns show less intense weathering with increasing depth in the log profile and support a simple weathering model.

Sand body geometry, constrained and predicted during a horizontal drilling campaign in a Lower Cretaceous turbidite sand system, Captain Field, UKCS Block 13/22a

The Captain Field is a large viscous oil accumulation located in the Western Moray Firth, UK Block 13/22a which is being developed by long horizontal wells. The reservoir sand body geometry was defined in the appraisal phase by 20 vertical wells. Seismic attributes were not used because of the poor seismic signal to noise ratio in the reservoir interval. As the development drilling campaign has unfolded, the appraisal sand body geometry model has been significantly refined using a wealth of data from the horizontal wells. During development drilling it has proved cheap to sidetrack horizontal well sections without a requirement to isolate the abandoned hole. This has resulted in significant extra geological data (e.g. top reservoir penetrations, sand thickness data). Integrating this dataset with top reservoir topography derived from seismic and weak internal reservoir seismic reflectors, the sand body geometry model is significantly improved in undeveloped parts of the field.

Occurrence, origin and implications of overpressure in the Malay and Penyu Basins, offshore Malaysia

There are four (4) common reasons why drilling of a well is terminated, namely reservoirs are not economical in the deeper section, reservoirs are poorly developed, operational problems and overpressure. Eighty percent of wells drilled in the Malay-Penyu Basin have been terminated either in anticipation or due to overpressure. This study uses pressure versus depth plots generated from RFT and DST readings taken in 94 exploratory well spread throughout the Malay-Penyu Basin. Overpressure in this area is found to be neither depth dependent nor age related. The margins of the Malay Basin and the entire Penyu Basin are fo~d to be normally pressured. The central portion of the Malay Basin is overpresswed. The onset of overpressure appears to be abrupt in the north and more gradual in the southern portion. Carigali drilled Resak 6F-18.4 in 1993 and successfully penetrated an overpressured zone finding hydrocarbon bearing reservoirs within and beneath this zone. An understanding of this phenomenon is crucial in the planning of safe and efficient drilling campaigns.

Structural and stratigraphic evolution of the Anza rift, Kenya

The Anza rift is a large, multi-phase continental rift basin that links the Lamu embayment of southern Kenya with the South Sudan rifts. Extension and deposition of syn-rift sediments are known to have commenced by the Neocomian. Aptian-Albian strata have, thus far, not been encountered during limited drilling campaigns and, in at least one well, are replaced by a significant unconformity. Widespread rifting occurred during the Cenomanian to Maastrichtian, and continued into the Early Tertiary. Marine waters appear to have reached the central Anza rift in the Cenomanian, and a second marine incursion may have occurred during the Campanian. As no wells have yet reached basement in the basinal deeps, the possibility exists that the Anza rift may have initiated in the Late Jurassic, in conjunction with extension to the south in the Lamu embayment and to the north in the Blue Nile rift of Sudan. Structural and stratigraphic evolution in the Anza rift followed a pattern that has now been inferred in several rift settings. Early phases of extension were accommodated by moderately dipping faults that produced large stratal rotations. Sedimentary environments were dominantly fluvial, with associated small lakes and dune fields. Volcanic activity is documented for the early Neocomian, but its extent is unknown. This initial style of deformation and sedimentation may have continued through several of the earliest pulses of rifting. By the Late Cretaceous, a new system of steeply dipping faults was established, that produced a deep basin without significant rotation of strata in the north, and only minor rotation in the south. This basin geometry favored the establishment of large, deep lakes, which occasionally were connected to the sea. The older basins were partly cannibalized during the sedimentary in-filling of these successor basins. Early Senonian volcanism was encountered in one well, and reflection seismic evidence suggests that one or more thick, regionally extensive igneous sills were intruded, probably during the Early Tertiary. The change in rift style from early, strongly rotational, shallow basins to late, non-rotational, deep basins has been observed in the southern Gulf of Suez/northern Red Sea, the Southwestern Turkana/northern Kenyan rift, and at Anza. It therefore takes place in rifts in variable tectonic settings, with a wide range of volcanic activity and, presumably, with different driving mechanisms. The shift in deposition in each case is away from early rift-bounding faults toward the half-graben flexural margins, further in-board to the upper structural plate. This suggests at least some component of regional simple shear in the deformation history of the rifted lithosphere, either via broad shear zones or at discrete detachment surfaces.

New oil discoveries in the Ceuta area, SE Lake Maracaibo, Venezuela

Abstract The Ceuta area forms the southeast extension of a major oil accumulation in the Maracaibo Basin, at present Venezuela’s main oil producing area. The Ceuta Field, with current reserves of 600 MMBBls of light to medium gravity oil, is a major wrench fault structure, producing from Miocene and Eocene sandstones. Several major transcurrent faults are recognized in the Maracaibo Basin, each defining major producing oil fields like the Ceuta Field. These structures, roughly parallel to each other, are oriented in a North-South direction. The principal plays in the Maracaibo Basin consist of Miocene and Eocene sandstones and, at greater depths, fractured Cretaceous carbonate reservoirs and fractured basement, all charged from the rich marine La Luna source rocks of Upper Cretaceous age. The discovery of the Ceuta Field was the result of an intensive drilling campaign executed in the 1970s, based on conventional seismic techniques. At that time the exploration of the area was oriented towards the main North-South trending structures. The new exploration, undertaken during the last four years, was based on the structural modelling of the area in terms of the known transcurrent faulting. This allowed the recognition, in areas between the major trends, of three new types of traps related to different styles of faulting, such as normal, compressive and antithetic transcurrent. The successful drilling of these structures has led to the discovery of an additional 1100 MMBBls of oil outside the existing Ceuta Field, confirmed by an intensive drilling appraisal campaign.

A note on the geochemistry procedures and the geochemical data base of the Ocean Drilling Program

We present a brief description of routine and special geochemical analyses, including methodology and instrumentation, performed onboard R.V. JOIDES Resolution SEDCO/BP 471 during drilling campaigns of the Ocean Drilling Program. The organic geochemical program is centered on hydrocarbon monitoring and produces data on organic matter abundance, composition, and maturity. Specialized equipment is available for examining interstitial gas composition and concentration, and lipid composition of solvent extracts. Interstitial water analyses measure major dissolved ions and nutrients. The structure and content of the ODP data base that incorporates these new data and those from 96 DSDP legs contains at present results of more than 95,000 analyses, mainly of carbonate and organic carbon content. Data base structure enables specific searches and relational sorting, which makes regional or temporal searches possible.

Riser Instrumentation: Deep Water Drilling Campaign Results

During the 1982–1983 drilling campaign in the Mediterranean, two wells were drilled by the Discoverer Seven Seas in record water depths of 1714 m and 1252 m. The riser was equipped with instruments to measure tensions, moments and angles at points close to the extremities. Simultaneously ship motions and environmental conditions including current measurements at various depths were recorded by ELF AQUITAINE and I.F.P. A large quantity of data relating to riser behavior was gathered and recorded. The results available for publication include raw data relating to the evolution of current at different depths, long period lateral ship motion acting at the riser top end, induced by the dynamic positioning system. Simultaneous measurements of angles at extremities were recorded to confirm the validity of two-dimensional riser analysis. Measurements of riser parameters made with deliberately large ship excursions from the vertical, enabled the riser practical profile to be compared with the theoretical one. Measurements, made with the riser hung off in storm conditions, confirmed the existence of large dynamic tensions and enabled them to be compared with the theoretical values. Correlation of the fluctuation of cable tension with ship heave has led to practical values of tensioner stiffness.

HYDROCARBON SIGNIFICANCE OF UPPER PALAEOZOIC SEDIMENTS ASSOCIATED WITH THE KOBURRA TROUGH, GALILEE BASIN

The Koburra Trough is a major tectonic feature in the northeastern Galilee Basin of Queensland. The oldest rocks identified in exploratory drilling were Devonian sandstone, shale and siltstone, possibly representing a northern extension of the Adavale Basin. These rocks contain a fossil microflora and may be prospective for hydrocarbons. Overlying them are a maximum of 1979 m of Upper Palaeozoic sediments, and a maximum of 1180 m of Triassic sediments, together comprising the Galilee Basin succession. The lithofacies of the Late Palaeozoic is dominantly sandstone-shale; the lower beds show evidence of glacial derivation, and the upper beds contain coal measures. Shows of oil and gas have been recorded from the basal part of the sequence in the two deep wells (ENL Lake Galilee −1 and FPN Koburra −1) drilled in the trough. Structural and stratigraphic factors favour the existence of hydrocarbon traps on the south-western flank. "Large" inferred reserves of Upper Permian sub-bituminous coal have been discovered in Geological Survey exploration near outcrop at the southeastern end. Preference in the use of this coal is to be given to manufacture in Queensland of synthetic fuels and petrochemicals. The geological survey petroleum statigraphic drilling campaign is providing invaluable new data on the Galilee Basin.

Engineering Planning and Supervision of Directional Drilling Operations

Abstract For many years the planning and supervision of directional drilling operations have been more-or-less limited to those organizations and individuals specializing in directional work. Without attempting to minimize the importance of and necessity for these directional specialists, operating companies have become increasingly aware of the contributions which competent engineering planning and supervision can make toward a successful directional drilling campaign. The part which such planning and supervision can play in directional operations is illustrated by a recent drilling campaign undertaken by Sun Oil Co. To test a Marginulina sand structure underlying a portion of the lower Texas Gulf Coast, three relatively large-displacement directional wells were drilled from Padre Island out under the Gulf of Mexico. While the hazards and limitations involved in drilling high-angle wells were recognized, the cost advantage of a successful directional campaign, as compared with other methods of drilling in the 20- to 40-ft waters, made the calculated risk well worth accepting. Careful and detailed planning preceded the operation. Among the factors considered were:selection of directional drilling specialists,study of rig requirements and selection of contractor,target tolerance,kickoff depth,casing and hole-size program, anddrilling mud program. With the exception of one short fishing operation, the directional operations progressed in a satisfactory and troublefree manner. On each of the wells approximately 9,000 ft of hole were drilled to secure horizontal displacements ranging from 3,900 to 4,500 ft at true vertical depths of 7,900 ft. Maximum angles ranged from 31 ½ to 43 ½. All holes bottomed well within target limits, and the drilling times, raging from 32 to 42 days, are considered quite good for this specialized operation. No difficulty was experienced with any of the casing or casing operations. Average cost of the directional wells was $125,000; it is estimated that vertical wells drilled by platform and tender or drill barge would have cost a minimum of $300,000 and probably $500,000. Sun's successful directional program may be attributed largely to the following factors, all of which enhance the chance for success on any directional program:careful planning; close, informed supervision, andadequate drilling rig and equipment; cooperative and experienced rig personnel; a competent and responsible directional specialist.

Paleozoic History of the Central Nebraska Basin and Its Relation to Anticipated Oil and Gas Exploration: ABSTRACT

The western part of the Central Nebraska basin, which appears to be a northward extension of the Salina basin of Kansas, has been the scene of active leasing and seismographic investigations during the past year, particularly in Harlan, Phelps, Kearney, Buffalo, Sherman, Valley, eastern Custer, and eastern Dawson counties and an active drilling campaign in this area is anticipated. Most of the interest seems to be localized within a broad band along the western side of the basin where the truncated edges of the pre-Pennsylvanian Paleozoic formations are overlapped by the Pennsylvanian and west thereof where there are stratigraphic trap possibilities in connection with Lower Pennsylvanian sands that may wedge out against the pre-Cambrian surface as it rises in the Cambridg arch. The known distribution, stratigraphy, and lithology of the pre-Pennsylvanian formations within this basin are discussed and the probable Paleozoic history of the region reviewed. The Pennsylvanian lithology, distribution, and facies changes are outlined. It is concluded that suitable reservoir rocks occur at reasonable drilling depths in connection with formations of several geologic ages although oil source possibilities and local structural conditions are hard to evaluate. Important unconformities at the base of the Mesozoic, at the base of the Pennsylvanian, and at the base of the Simpson present some interesting possibilities but also suggest that the region should not be condemned on the basis of a comparatively few tests that may not be located to test more than one possibility dequately. End_of_Article - Last_Page 2606------------

Subsurface Devonian and Silurian sections across northern Pennsylvania and southern New York

Research Article| June 30, 1933 Subsurface Devonian and Silurian sections across northern Pennsylvania and southern New York CHARLES R. FETTKE CHARLES R. FETTKE 2Published with the permission of the State Geologist of Pennsylvania. Search for other works by this author on: GSW Google Scholar GSA Bulletin (1933) 44 (3): 601–660. https://doi.org/10.1130/GSAB-44-601 Article history received: 28 Feb 1933 first online: 02 Mar 2017 Cite View This Citation Add to Citation Manager Share Icon Share Twitter LinkedIn Tools Icon Tools Get Permissions Search Site Citation CHARLES R. FETTKE; Subsurface Devonian and Silurian sections across northern Pennsylvania and southern New York. GSA Bulletin 1933;; 44 (3): 601–660. doi: https://doi.org/10.1130/GSAB-44-601 Download citation file: Ris (Zotero) Refmanager EasyBib Bookends Mendeley Papers EndNote RefWorks BibTex toolbar search Search nav search search input Search input auto suggest search filter All ContentBy SocietyGSA Bulletin Search Advanced Search Abstract IntroductionAn open flow of 3,500,000 cubic feet of natural gas per day in the upper part of the Tully limestone in a well northwest of Richburg in Allegany County, New York, in September, 1928, started an active drilling campaign which has extended over a large part of west-central New York and adjacent parts of north-central Pennsylvania. This led to the discovery of the Wayne-Tyrone gas pool in Schuyler County, New York, in March, 1930; the Tioga pool in Tioga County, Pennsylvania, in September, 1930; and the Hebron pool in Potter County, Pennsylvania, in November, 1931. In these three pools the gas occurs in the Oriskany sandstone.From a great many of the wells complete sets of drill cutting samples have been taken, so that accurate sections of the strata penetrated can be constructed. Through the courtesy of companies and individual operators engaged in drilling in this area, samples from . . . This content is PDF only. Please click on the PDF icon to access. First Page Preview Close Modal You do not currently have access to this article.

Unit Operation in California

No outstanding example of an important producing unit operation exists in California today where the competitive drilling drainage feature is or wasentirely eliminated We need not feel, however, that the thought of unitoperation had its birth in 1924, when Henry L. Doherty named and sponsored itso strongly before the American Petroleum Institute and our own organization.No man or company in California ever drilled a wildcat well without exertingevery possible effort to get all of the structure, so as to control drillingand avoid competition. Overproduction did not begin in 1923, so there hasalways been the wish to avoid it. In this state the practice of selling acreagearound a wildcat has not been followed, except possibly in rare instances. Theoperator drilling the wildcat knew he must pay the bill alone, so he endeavoredto get the benefit of his effort by tying up all of the land around his welland by so planning his different lease obligations as to avoid as muchoffsetting as possible. If he failed to get all of the land, it was becausesomeone's price was too high, some other oil man also had the same idea andalready held some lands, a competitor took leases away from him while his workwas still incomplete, or (as was so often the case) the hidden structure whendeveloped did not prove to be where the wildcatter thought it would be. Thelast named condition often led to a forced drilling campaign by the last leasessecured and thus to serious drilling drainage problems. Ownership of the Land The land situation differs a great deal in various parts of the state. In theSan Joaquin Valley, all the land is surveyed into sections and townships.Railroad land grants embraced a part of the land. In the areas that weredeveloped at an early date, as at Kern River, Coalinga, McKittrick and theSunset-Midway field, such land as the railroad company's diligent landdepartment had been unable to sell for a song as grazing land still remained inits ownership.

Improved Drilling and Production Methods in the Gulf Coast Field

The great number of wells being drilled in the Gulf Coast creates a greatdemand for and an opportunity to improve the methods of drilling wells and ofproducing oil from them. Some improvements have been made, but in the presentstrenuous drilling campaign at Spindle top, the quickest methods of drillingand completing wells are much too slow. Therefore, not a great deal of thoughthas been given to new methods. However, one can not help but compare the method and equipment used in thepresent-day drilling campaign at Spindletop with those of 1901. The differencesin equipment and methods are staggering and the present-day operators canhardly imagine how the old operators ever were able to drill a well. The"old timers" explain the reason as being that "Men were men inthose days and not much machinery was necessary." Yet the development in 25years of thought and study has brought about a great improvement in equipmentand in methods. I believe there has been a great deal more thought given to the developmentand improvement of drilling equipment and methods and to the completion ofwells than has been given to the actual production operations. Drilling Methods and Equipment The greatest improvement that has been made in the methods of drilling andcompleting wells in the Gulf Coast is in the rotary equipment machinery used indrilling. Equipment more suitable and applicable to the duty imposed indrilling wells has been and is being steadily developed. The operators are nowstudying and are beginning to find out just what work, what duty the machinerywill have to perform before a well can be drilled to the various depths in thequickest time and in the best possible manner. I think more than ever before the oil operator is making "carefuldiagnosis of drilling conditions," such as the character of formations tobe drilled, the depth of the hole, the size of the hole, the manner and sizesof pipe to be set and the time required to drill to certain depths.