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In Chevron's Gulf of Thailand (GOT) operations, costs drive logging and formation evaluation. Programs for logging and evaluation are based on consideration of perceived value and the potential for comprehensive utilization. Well lifespan is short, and economics rarely provide for the use of higher technology at non-discounted prices. A recent business initiative recognized that oil vs gas fluid identification from logging measurements was a risk that should be mitigated providing a major opportunity to add value. Historical experience has shown, that the diameter of invasion can be greater than twenty inches by the time a well is logged with wireline which is beyond the limits of investigation for density and neutron tools, rendering the interpretation of fluid types ambiguous in most hydrocarbon bearing sands in this basin. To reduce this uncertainty, comprehensive wireline formation pressure programs have been run to assess hydrocarbon gradients but because sands are thin and permeabilities are low these programs have had various degrees of success. LWD (logging while drilling) neutron tools can obtain data prior to invasion. Overlaying the LWD neutron and wireline neutron reveals time-lapse differences between the logs, shows gas intervals, and confirms liquid-filled zones. The technique can also infer inflow permeability for some of the more shaley gas reservoirs. Positive fluid identifications have been confirmed by follow up wireline pressure gradients, NMR logs, and production tests. This paper will show many great examples of the evolution of a good idea. It will also demonstrate the effective use of technology, the buy-in from drilling engineers, and value of information benefits to the asset teams. Logging programs in the GOT once thought to be static, have rapidly evolved with insightful technology and the demonstration of its value. Geology Overview GOT Chevon's GOT operation is focused within the Pattani basin which is located near the geographic center of the Gulf of Thailand containing in some areas greater than 25,000 ft of almost entirely non-marine fluvial and delta plain sediments. The basin is characterized as a primarily north-south trending extensional system with virtually no evidence of subsequent inversion. Accommodation with control from basement block faulting has enabled the formation of en echelon graben systems resulting in a multitude of fault related structural and stratigraphic closures. Significant amounts of gas and liquid hydrocarbons have migrated into these horst and graben structures from localized coal and lacustrine source rocks. The fluvial depositional systems that provide the ubiquitous reservoir rocks in the basin developed on an extensive delta plain throughout the Neogene. Meander belts and associated point bars occasionally stack to form thicker reservoir units but sands are generally thin (less than 20 ft) and have relatively small accumulations (column and area) of hydrocarbon (Crossley. 1990). The key success of the drilling campaigns is to locate as many of these accumulations with one well, and comingle the reservoirs of known gas and lift the liquid hydrocarbons with single gas accumulations. To accommodate this strategy identifying the producible hydrocarbons and more importantly the hydrocarbon type within the multiple reservoirs found in a given well that may or may not be correlated to the offset wells is critical for success. Misidentifying the fluid type has led to difficulties in correlation as well as numerous missed opportunities to capture the reserves in a given well using the most effective completion methods. The technology described below has been of great assistance in Chevron? s operation to mitigate this risk.
In Chevron's Gulf of Thailand (GOT) operations, costs drive logging and formation evaluation. Programs for logging and evaluation are based on consideration of perceived value and the potential for comprehensive utilization. Well lifespan is short, and economics rarely provide for the use of higher technology at non-discounted prices. A recent business initiative recognized that oil vs gas fluid identification from logging measurements was a risk that should be mitigated providing a major opportunity to add value. Historical experience has shown, that the diameter of invasion can be greater than twenty inches by the time a well is logged with wireline which is beyond the limits of investigation for density and neutron tools, rendering the interpretation of fluid types ambiguous in most hydrocarbon bearing sands in this basin. To reduce this uncertainty, comprehensive wireline formation pressure programs have been run to assess hydrocarbon gradients but because sands are thin and permeabilities are low these programs have had various degrees of success. LWD (logging while drilling) neutron tools can obtain data prior to invasion. Overlaying the LWD neutron and wireline neutron reveals time-lapse differences between the logs, shows gas intervals, and confirms liquid-filled zones. The technique can also infer inflow permeability for some of the more shaley gas reservoirs. Positive fluid identifications have been confirmed by follow up wireline pressure gradients, NMR logs, and production tests. This paper will show many great examples of the evolution of a good idea. It will also demonstrate the effective use of technology, the buy-in from drilling engineers, and value of information benefits to the asset teams. Logging programs in the GOT once thought to be static, have rapidly evolved with insightful technology and the demonstration of its value. Geology Overview GOT Chevon's GOT operation is focused within the Pattani basin which is located near the geographic center of the Gulf of Thailand containing in some areas greater than 25,000 ft of almost entirely non-marine fluvial and delta plain sediments. The basin is characterized as a primarily north-south trending extensional system with virtually no evidence of subsequent inversion. Accommodation with control from basement block faulting has enabled the formation of en echelon graben systems resulting in a multitude of fault related structural and stratigraphic closures. Significant amounts of gas and liquid hydrocarbons have migrated into these horst and graben structures from localized coal and lacustrine source rocks. The fluvial depositional systems that provide the ubiquitous reservoir rocks in the basin developed on an extensive delta plain throughout the Neogene. Meander belts and associated point bars occasionally stack to form thicker reservoir units but sands are generally thin (less than 20 ft) and have relatively small accumulations (column and area) of hydrocarbon (Crossley. 1990). The key success of the drilling campaigns is to locate as many of these accumulations with one well, and comingle the reservoirs of known gas and lift the liquid hydrocarbons with single gas accumulations. To accommodate this strategy identifying the producible hydrocarbons and more importantly the hydrocarbon type within the multiple reservoirs found in a given well that may or may not be correlated to the offset wells is critical for success. Misidentifying the fluid type has led to difficulties in correlation as well as numerous missed opportunities to capture the reserves in a given well using the most effective completion methods. The technology described below has been of great assistance in Chevron? s operation to mitigate this risk.
Measurement-while-drilling (MWD) information accurately defined gas, oil, and water in an offshore field. Basic MWD and wireline formation evaluation data compare favorably. A cost saving of $130,000 was realized when MWD information was used instead of wireline data on one well. In the future, MWD logs may serve as the primary evaluation data on routine development wells in similar fields.
Summary Like comparable wireline measurements, measurement-while-drilling (MWD)formation-evaluation tools are dependent on the borehole condition. Because ofthis dependency, the borehole size must be known for appropriate boreholecorrections to be made to porosity measurements. This paper describes calipermeasurements that can compute the effective diameter of a uniform or nonuniformborehole with nonmechanical means. The basis for the caliper measurement is agamma/gamma density sensor that uses asymmetric detector placement to definethe borehole size. The derivation of the caliper is presented with field logcomparisons. Introduction Because sensor capabilities are being added regularly to MWD systems, bottomhole-assembly (BHA) design must now contend with variables absent in thepre-MWD era. New considerations include MWD assemblies of a given OD that areless stiff than the BHA components they replace I and, depending on theparticular drilling application desired, a different MWD sensor placed near thebit. Proximity of a given sensor to the bit is compromised further by Proximityof a given sensor to the bit is compromised further by the increasing use ofsteerable systems. These, by their very nature, require a motor near the bit, and directional sensors require additional nonmagnetic collars in proximity. All this requires that formation-evaluation-while-drilling (FEWD) sensors beplaced as far as 200 ft from the bit. In some drilling placed as far as 200 ftfrom the bit. In some drilling environments, this can result in the boreholebeing significantly enlarged by the time FEWD sensors evaluate the rock. Borehole enlargement is of particular concern for two reasons. First, from adrilling viewpoint, whether the hole enlargement occurs rapidly or slowly mustbe determined; i.e., is the borehole stable or unstable, and does knowing thestability of the borehole improve our understanding of the drilling conditions?Second, from a FEWD viewpoint, can we infer or measure the true borehole sizeso that the formation-evaluation sensors can be interpreted properly. This isvery important in the case of nuclear formation-evaluation tools because, likestandard wireline nuclear tools, they are very sensitive to boreholeconditions. This borehole sensitivity implies that, to achieveformation-evaluation quality comparable with wireline, comparable knowledge ofthe borehole while drilling is necessary. Borehole enlargement now can bemeasured while drilling with a nonmechanical sensor that uses multiple detectormeasurements to determine the average borehole caliber. This average can thenbe displayed as a continuous curve in the same manner as traditional mechanicalcalipers. We calibrated the new borehole caliper measurements for various muddensities and borehole diameters. We observed that repeat sections or wipedlogs after drilling indicate the same size or larger borehole. We obtained goodagreement (within 3% to 10%) between dipmeter (x-y) caliper measurements andthe measurements made while drilling and found that the geometric average ofthe wireline x-y dipmeter caliper was larger than or equal to the measurementmade while drilling. These results were obtained at drilling rates ofpenetration (ROP's) of up to 500 ft/hr. A borehole-size measurement made whiledrilling allows us to make the borehole corrections required by nuclearporosity sensors and to calculate the cement volume without making a separatetrip into the borehole. Design Constraints MWD assemblies are used in the fall range of well types, from straight-holeexploratory wells to horizontal wells. Consequently, these assemblies must beincorporated into the full gamut of BHA types. Nonmotor BHA designs arecategorized as building, holding, and dropping assemblies. The relativeplacement of only three full-gauge stabilizers near the bit produces the fullrange of desired angle changes, from aggressive build to aggressive drop. Smallextents of undergauge on the blades (less than 0.5 in.) moderate aggressiveassemblies. The foregoing emphasizes that the placement and diameter ofstabilizers are key to controlling build/drop tendencies. To remain minimallyintrusive to this process, we specified that our porosity sensor (andassociated caliper device) design not require wall contact. This specificationhas the virtue of not complicating drilling situations where slick ornear-slick assemblies are dictated by hole conditions. A final advantage is inpendulum dropping assemblies, where the closest available pendulum droppingassemblies, where the closest available stabilizer is commonly 60 ft from thebit. In addition, because the borehole is rarely circular, the caliper must becapable of making valid measurements in oval or elliptical boreholes. Finally, because the nuclear FEWD sensors are sensitive to the borehole size andenvironment (such as mud density), an MWD caliper must have an accuracy on theorder of 0. 125 in. We imposed three restrictions, which are inherent to our MWD borehole caliper measurement:there can be no mechanical protuberancesto interfere with the drilling operation,the protuberances to interferewith the drilling operation,the caliper measurement must be capable ofaccurately averaging a noncircular borehole, andthe caliper must beaccurate to 0. 125 in. Theory of Operation To meet these restrictions, we used the Simultaneous Formation Density (SFDSM) sensor to make the required measurements. The SFD sensor is the samegamma/gamma density too] described by Paske et al. 5 Fig. 1 shows the tool incross section. The basic tool has four detector banks on the circumference ofan insert placed inside a drill collar. The detectors are placed with two axialspacings to the cesium- 137 gamma source. The front detector bank in Fig. 1 isdirectly above the cesium source, and axially, is farthest from the source. Theother three detector banks are placed at the same axial distance from thecesium source. By placing the SFD tool in the various test pits shown in Fig.2, the formation response of the individual detector banks can be determined asfunctions of the borehole diameter and the borehole mud density. These testpits consist of four limestone rock stacks and 12 density tanks. The tanks areused to determine the mud density effects on the nuclear sensors. Fig. 3 showsthe borehole dependence for one detector bank. The solid line fit in Fig. 3 isgenerated from the equations below.
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