14c_value of geophysics in the production of bay marchand field

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Case History 10

Value of Geophysics in the Productionof Bay Marchand Field

William L. Abriel, Chevron Energy Technology Company; William Haworth, Chevron North

America Exploration and Production Company

This is the story of how geophysics has helped Chevron produce more oil and gas fromBay Marchand than from any other field in the Gulf of Mexico. From 1938 until today,geophysics has had a measurable impact during discovery, delineation, developmentproduction, and revitalization of the geologically complex field. During this time, as geo-physical technology has become available it has been applied with largely successfulresults.

High-impact geophysical techniques applied to date and described in this paper includegravity, refraction seismic, 2-D reflection seismic, 3-D production seismic, high-resolution3-D seismic, and time-lapse seismic (4-D). Additional applications of high-end geophysicatechniques include inversion, AVO, shear-wave seismic, prestack time imaging, and depthimaging. The interest in and ability to use so many of the geophysical tools of the industryare due to both the geologic complexity of the field and the fortunate conditions of beingin a generally good seismic-data area.

The role of these geophysical techniques is documented, and their impact is measuredthroughout the life of the field. Not only were the initial discovery and developmentsupported by geophysics, but after production maturity and decline, geophysics had aprimary role in the revitalization of the field and substantially extended the productionlife, which continues today.

A much shorter case history of Bay Marchand field was included in earlier editions ofthis book and also published as Abriel et al. (1991). This case history is a considerableexpansion, starting earlier and finishing later in the fields history.

Bay Marchand field is a complexly faulted salt dome (Frey and Grimes, 1970) along thenorthern edge of the Gulf of Mexico shelf (Figure 14-10-1). The field is characterized by anumber of structural and stratigraphic traps (Figure 14-10-2).As the dome was emplacedand altered during geologic history, major and minor faults both provided pathways forhydrocarbon migration and also provided traps for accumulation. Proximity to the saltand its history of movement also have had a substantial impact on the sedimentation ofmarine regressive sand reservoirs and associated sealing shales.

The field has produced from more than 50 sands, ranging in age from Pleistoceneto middle Miocene, and from depths of 1000 ft to over 15,000 ft (3004600 m) subsea.The complexity of faulting, along with stratigraphic variation and the large number ofproductive sands, resulted in more than 500 individual combination traps with varyingfluids, pressures, and production characteristics. This situation has resulted in the drillingof more than 1200 production wells from 1950 to today each targeted to a specific

development or enhanced-recovery concept.As with geophysical technology, reservoir management and drilling engineeringtechnologies have addressed the geologically complex field, and have consistentlybeen improved and applied to maximize production value. Production advances fromwaterflooding to horizontal drilling were applied as they developed in the industry. Theapplication of geophysics to the field has directly supported these production-engineeringactivities by addressing answers to the issues of geologic complexity.

In the initial exploration phase of the United States Gulf Coast, gravity data were animportant tool in oil exploration, as they provided a primary method of locating large salt

Introduction

Geologic Setting

Discovery

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domes expected to act as collecting areas for oil and gas. Bay Marchand salt dome wasinitially recognized by this method in the late 1920s, as were many other large domesalong the south Louisiana coast (Figure 14-10-3). At that time drilling onshore was theonly option, and Gulf Oil Company attempted this on the northern salt flank in 1930.Unfortunately, they were not successful in discovering hydrocarbons.

But not being discouraged by this, other companies drilled an additional nine dry holesonshore over the next ten years in search of oil. And one additional well had even been

attempted with new technology offshore drilling.Gulf was there first at the very topof the salt dome andin 1941 found anuneconomic accumulation with 25 feet of gas in thePP-1 well (Figure 14-10-4). Chevron (then Calco) conducted a reflection seismic surveyand acquired more than 25,000 leased acres in 1947 and 1948. Utilizing the new reflectionseismic and an existing refraction survey, they proposed three wells in September 1948.The first well (A-1) encountered salt near the crest of the dome and was a dry hole.

The B-1 and C-1 follow-up wells were designed to test opposite flanks of the dome andwere drilled simultaneously. Both were successful. The B-1 well, the 13thexploratory wellin the area, was credited as the discovery well and was completed as an oil producer froma depth of 2,8732,892 ft in March 1949 (Figure 14-10-4). After 19 years of exploration, thegiant Bay Marchand field came into existence.

Immediately after the fields discovery, exploitation proceeded with the installationof three development platforms that had a total of 12 directional wells (Figure 14-10-5).The first platform installed was made of wood and remained in production for decades.The other platforms employed a new facilities concept iron legs and an iron deck. Allof this was accomplished by 1951, when production was initiated and further delineationwas planned.

To support this additional delineation program, a more extensive refraction programwas acquired to map the position of the salt-sediment interface, as proximity to salt wasconsidered to be the key to oil accumulation. The A-1 well, which had penetrated salt,was used for a refraction survey in 1950. The well site was used as a position for dynamiteshotpoints, and receivers were deployed extensively over the ocean bottom and above thedome (Figure 14-10-6). Seismic traveltimes from the shots were carefully measured, and

the seismic waves that traveled through salt and along the salt-sediment interface wereplotted in depth. The interpretation of the refraction data produced a detailed salt contourmap in 1951 (Figure 14-10-7). This map is the first complete representation of the domeand rather closely resembles what we know today. Of special note is the identification ofa salt overhang on the east flank a concept that was lost in the 1960s only to reemergeagain in the late 1980s.

During the aggressive development of the field in the 1950s, early delineation focusedon the reserves located near the crest of the dome. Over time, delineation proceededdown the flank of salt and resulted in finding additional reserves in both the north andeast flanks (Figure 14-10-8). Production geology was the foundation of this developmenteffort, with correlation of well logs as the critical subsurface data. What existed between

wells was estimated on the basis of geologic models and imagination.Delineation and development proceeded even farther down the flanks in the1960s, extending production to the east and south (Figure 14-10-9). At that time,more expensive drilling of deeper reservoirs was supported by limited 2-D seismicreflection data. Those seismic data were good at predicting large faults and generaldip rates but lacked the appropriate resolution to handle stratigraphic information.By the late 1960s the field reached its greatest development activity, having morethan 800 wells, and was at its historical peak (Figure 14-10-10). The majority ofdevelopment effort was done with geologic imagination and widespread drillingin just about every corner imaginable. There didnt seem to be much space left forfinding new significant reserves.

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Peak production for the field (80,000 BOPD & 84 MMCFG/D) occurred in 1967. By the1970s, production went into decline (Figure 14-10-10). That decline occurred despite theinitiation of waterflooding and pressure maintenance in a number of the larger reservoirson the east flank of the field. It was at that time that 2-D seismic reflection data began tosignificantly influence the geologic thinking about the field. With the advent of digitalprocessing, seismic sections improved enough that they were used more commonly forstructural analysis. In addition, the ability to preserve amplitude information was beneficial

in the recognition of some stratigraphic attributes of the subsurface (Figure 14-10-11). Withproper amplitude analysis, the direct detection of some hydrocarbons (especially gas) wasalso possible.

Two-D seismic data became a good tool for providing new subsurface information.With the geologic complexity of the field, valuable information was needed between thealready close well interval, and seismic data provided the tool to show the inter-wellgeology. An extensive grid of 2-D seismic data was acquired (1) to support structuraland stratigraphic models for the enhanced recovery, (2) to help locate production andinjection wells, and (3) perhaps to find hidden reserves (Figure 14-10-12). Drilling duringthis period was less frequent than in prior decades and was targeted at potential newaccumulations or specific wells needed to fine-tune production (Figure 14-10-13).

By 1984, production was in significant decline to the extent that Chevron reluctantlybegan the process of putting the field up for sale. Two-D seismic data had been acquiredover most of the field, and apparently there werent many places left to develop. Afterall, what more could be learned about such an extensively drilled asset? It was clear thatthe field was rapidly becoming uneconomic despite the use of enhanced oil recoverytechniques and the best geology and geophysics available. It was time to get out.

But wait. A new technology was emerging that showed significant promise insubsurface geology 3-D seismic data. Exploration in the Gulf of Mexico was undergoingan exciting new era in the early 1980s as structure and stratigraphy were being revealedin 3-D cubes with reflections accurately placed in their correct position. Old maps werebeing revised, and new plays were coming to light. Some geologic rules of thumb werebeing abandoned as the 3-D observations were coming in. What were the odds that this

could impact an asset like Bay Marchand? Would new geology be revealed? Geophysicistscertainly thought so, and the field management approved a project to acquire the first fullfield-scale 3-D seismic data specifically designed to support production.

If the 3-D survey was to be cost effective, it would have to have very significant impact.The price of acquisition and processing was the equivalent of ten new production wells,or approximately the entire years drilling program. The seismic acquisition might notinterfere with present production practices, but it would significantly delay much-neededproduction additions. A planned drilling program of 12 wells was put on hold pendingthe outcome of the survey, and the cash marked for those wells was moved to the seismicbudget for acquisition of 3-D, which commenced in 1986.

The decision to acquire 3-D seismic data was based on anticipated success from three

primary objectives:

Increase reserves by delineating new reservoirs in structural and stratigraphic traps. Increase production by identifying additional production-well locations in existing

reservoirs. Enhance reservoir management through the unification of geology, geophysics, and

reservoir engineering, thus obtaining better models for reservoir simulation andoptimizing the location of water-injection wells for enhanced oil recovery.

In order to obtain a data set with exceptional quality, acquisition design objectiveswere set to cover the entire survey area with 60-fold data on a 55-ft-square bin. This was

For Sale TheLargest Oil Field

in the Gulfof Mexico

The 1986 3-D

Seismic Project

Field Maturity



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accomplished with Westerns Digiseis telemetry receivers and a recording ship equippedwith a marine air-gun source. The geometry pattern was set with rows of hydrophonereceivers placed at the seafloor every 220 ft (67 m) (Figure 14-10-14). Two rows wereplaced 880 ft apart. Air-gun sources were fired in a grid 110 ft inline and 220 ft crossline,resulting in subsurface bins of nearly identical offset and azimuth.

Although this design was attractive from a geophysical standpoint, it requiredsignificant effort to obtain because the field contained 114 production platforms, two

major consortium pipelines, plus countless subsea production flow lines, power cables,and support systems (Figure 14-10-15). Westerns outstanding acquisition team providedperfect coverage of the field by placing receivers under platforms or swapping shotsand receivers. Every bin in the survey had exactly the same fold offset and azimuthdistribution to cover the 60-sq-mi (155 sq km) survey.

Three-D seismic data for the Bay Marchand field had a major impact. With the abilityto image the reservoirs between wells, the original objectives of the survey were met, andproduction increased significantly.

Most of the salt dome was covered in the acquisition. An example seismic line overthe top illustrated the very sharp and even angular nature of the salt-sediment interface(Figure 14-10-16). For the first time, both large- and small-scale faults could be accuratelylocated and subtle details of stratigraphy inferred from amplitude changes on reflections.And because the data are represented in a cube, time and horizon slices could beanalyzed. Surprising structural relations were revealed, such as the complex faultingof the salt dome and the horizontal sharp corners of the salt where faults intersected(Figure 14-10-17).

Recognition of the potential of this new information made it clear that the priorproposed drilling program was not well positioned, and that program was recycled sothat new drilling opportunities could go forward. Over the next two years, twenty-threenew production wells were located and drilled on the basis of the concepts revealed bythe 3-D seismic data. All twenty-three wells were a success, and the new reserves wereput into the production stream.

Some new reserves revealed by the 3-D seismic data were related to the identification

of new fault blocks. Even in a densely drilled field with more than 800 wells, there wasroom to find untapped oil and gas. An example of this was the drilling of infill well #40.The producing interval was penetrated by numerous wells (Figure 14-10-18), and yetthere was room for one more. A time slice showing the salt-sediment interface revealedan unknown embayment holding potential reserves (Figure 14-10-19). A new well wasplanned to drill into the embayment where high-amplitude reflectors suggested thepresence of oil and gas that were not being produced (Figure 14-10-20). The well foundboth oil and gas in this structural embayment (Figure 14-10-21).

New structural information began to come to light in many places over the field. Anexample on the east flank is a case in point. A map of the producing reservoir (Figure 14-10-22) had been constructed from 40 well correlations and 2-D seismic data shot on a gridof 2000 ft. The fault intersections, log correlations, fluids, and pressure were all employedto map out areas of gas, oil, water, reservoir shale-outs, and new potential. However,

when the 3-D seismic data were employed using the same well and engineeringinformation, a new map of the reservoir showed a significantly different picture (Figure14-10-23). Fault locations and sense of motion were changed. This opened opportunitiesto find undrilled reserves, and three new successful wells were immediately drilled onthis new interpretation.

Additional reserves were uncovered by the recognition of stratigraphy from seismicdata. For the first time, seismic amplitude measurements were found to be trustworthyenough to directly map reservoirs. Seismic sections such as Figure 14-10-24 revealedboth subtle and dramatic changes in amplitude. But when the seismic horizons werepicked and then represented in map view, the geology became apparent from the horizonslice (Figure 14-10-25). With this powerful tool, it was possible to search for bypassedstratigraphic traps.

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An example of using seismic amplitude for understanding the impact of stratigraphyon field production is provided by a sandstone reservoir on the west flank. Several wellshad penetrated the reservoir, which was producing oil. Some stratigraphic complicationswere recognized, such as a local shale-out and several permeability barriers, on the basisof production history and pressure measurements (Figure 14-10-26). The horizon slicefrom the seismic data (Figure 14-10-27) clearly revealed the location of quality reservoirsands that were not being produced, and subsequent drilling brought these areas under

production. Later, the smaller amplitudes to the south were successfully drilled as well,and those reservoirs were developed.

As illustrated in the previous examples, the 3-D seismic data directly detected newfault blocks and bypassed reserves. In addition, the seismic data also played a role inreservoir management through reservoir characterization. The key parameters thatseismic data provided were reservoir and aquifer structure, gross interval thickness,porosity, net pay, and the location of original fluid contacts. An example of this is shownin the characterization study of the FX reservoir as a potential waterflood candidate.Although the reservoir was never waterflooded, the characterization study is an excellentexample of the impact that seismic data can have on reservoir modeling.

The FX reservoir had two oil-producing wells, numbers 24 and 25 (Figure 14-10-28)In addition, the reservoir was penetrated by a downdip well in the aquifer and an updipwell that was shaled out (Figure 14-10-29). Production and pressure decline suggestedthat the oil system would be closed. A reservoir characterization was performed usingseismic data support and compared with a characterization using only the well data.The characterization using the seismic data showed the potential for an additional 26%cumulative production over that of the model using only well data.

Three-D seismic data amplitudes of the 8200 sand show strong reservoir heterogeneity(Figure 14-10-30). The high-amplitude reflections of the top (red) and base (blue)of the unit extend well below the oil-water contact and thus are not a function ofoil saturation but instead of reservoir porosity. The horizon slice of the reservoirreflectors (compensated for tuning) (Figure 14-10-31) shows that wells G-3, 24, and 25lie approximately within the yellow reflection response. The porosity-thickness of thethree wells is also similar. Using only the well data, the reservoir would appear to be ofconstant thickness and homogeneous in porosity, with local updip shale-out at well 27.

However, when we view the seismic response on the horizon slice, we can see some veryhigh-amplitude areas between the wells, which indicates thick and porous reservoir notseen in the well control. A net-sand map generated from the horizon amplitudes and timethickness shows the inter-well thicks and thins (Figure 14-10-32).

The net-sand map is a fundamental element of the volumetric calculations of thereservoir. The total oil volume can now be calculated and the amount producedsubtracted to calculate the remaining oil potential. If the pressure history is then takeninto account, it can be estimated that only about one-third of the total oil recovery ispossible without pressure support. Thus, two reservoir simulations were run to estimateand predict the effect of injecting water into well G-3. One simulation was done from acharacterization using only well parameters, and a separate and more heterogeneousone using parameters from seismic attributes (Figure 14-10-33). The resulting predictionsof oil production at well 25 (Figure 14-10-34) show more than 28% greater oil recovery

anticipated from the reservoir, if the seismic characterization is correct.From the examples shown above, it can be seen that the 3-D seismic data weresuccessful in meeting the primary objectives of finding new reserves, optimizing newproducer and injector locations, and supporting reservoir characterization and reservoirmanagement. An additional benefit of the 3-D seismic data was the ability to supportthe new drilling concept of horizontal wells, which were able to increase productionrates per well. As a result of the new geologic information provided from the 3-Dseismic data, an aggressive program was initiated to increase production. The successfulproduction increase has significantly added to the value of the Bay Marchand field andhas revitalized production (Figure 14-10-35).



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The 1986 3-D survey covered a great deal of the Bay Marchand field, but additionalareas needed more complete coverage. With the impact of 3-D seismic data well proven,additional 3-D seismic data acquisition continued in order to extend the coverage tothe entire field. A west-flank survey was acquired to identify bypassed oil and provideresolution of thin-bed stratigraphy. A north-flank extension was acquired in 1998. Thissurvey included data acquired in the onshore area merged with the offshore data. Again,those data provided indication of new fault blocks and bypassed reserves. As time

progressed, service companies had acquired several speculative 3-D surveys that covereddifferent portions of the field (Figure 14-10-36), and a decision was made to attempt tomerge these into one consistent data set.

Merging was not a simple task, given the number of differences in the surveys. Sourceswere different, receivers used were both marine-streamer and ocean-bottom hydrophonereceivers, and different recording systems were used as well. Stacks of the seismic datadid not match (Figure 14-10-37), and significant cross-equalization in processing wasrequired. Unmigrated gathers were used as input, requiring time, phase, and amplitudematching. The result of merging surveys (Figure 14-10-38) provided a much betterregional picture of the geology. Fine-scale faulting was revealed, and further prospectingwas enabled at the field edges. An additional benefit of survey merging was preparationof the data for 3-D prestack time and depth migration. And because there is overlap inspace and time, the data could be used for time-lapse seismic analysis.

The 1986 3-D seismic survey prompted a review of most reservoirs that showed seismicresponse. Amplitude data from horizon slices were prime attributes for analysis, andmany new stratigraphic views of the reservoirs were revealed, resulting in the location ofbypassed fault blocks and stratigraphic traps. But at times, the seismic data did not fit theknown stratigraphic model and suggested the detection of oil movement (Figure 14-10-39).

Oil bright-spot analysis was not common in 1986, and the suggestion that producingwater fronts could be seen with seismic data was received with great skepticism. Andyet, the data were of excellent quality and no other good explanation fitted all theobservations. Gradually the concept was accepted, and engineering models began to

take into account the seismic response. This led to identification of bypassed oil andrecognition of significant geologic heterogeneity.Mapping oil movement with seismic acquired at time intervals (4-D) was considered

to be possible for some reservoirs in Bay Marchand, and a project was initiated. Keyelements in the work included (1) petrophysical studies to determine strength of seismicsignal from water movement, (2) reservoir characterization sufficient to support a 4-Dseismic response, (3) forward seismic modeling for acquisition and processing parameters,and (4) selection of an acquisition technique to provide time-lapse data.

Petrophysical modeling showed favorable characteristics for 4-D seismic reservoirmonitoring. Data from wells logged before and after production are appropriate datafrom which to make predictions and show that at times, the seismic response fromoil production in Bay Marchand can be very dramatic. Because some reservoir sandsare much lower in density than the encasing shales, they generate good reflection

characteristics even when they are water wet (Figure 14-10-40). With the introductionof oil containing dissolved gas, velocity decreases significantly, creating an even higherimpedance contrast (reflection coefficient), and an oil bright spot is formed. Then whenthat oil is depleted because of oil production and the voids are replaced with water, as isthe case in strong water-drive reservoirs, the reservoir velocity decreases significantly andproduces a large dimming of the amplitude in the water-swept areas.

In order to support reservoir monitoring from seismic data, a reservoir characterizationwas initiated in 1995. Its purpose was to compute the oil flow from reservoir simulation,forward model the seismic response to generate synthetic 4-D data, and thencompare those data with 4-D seismic data actually acquired. To build the reservoir

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characterizations, a team of geologists, geophysicists, and reservoir engineers from theGulf of Mexico Business Unit and the Chevron Energy Technology Company (ETC) wasassembled to build appropriately complex geologic models using well data, seismic data,and geostatistics. This team leveraged the detailed knowledge of the field possessed bythe Gulf of Mexico personnel with the understanding of the new technology by ETCrepresentatives. The procedures developed by the team have carried over into Chevronsreservoir-characterization work flows today. Within the reservoir characterizations, earth

properties for seismic modeling were assigned and forward geophysical modeling wasperformed.

Forward modeling showed that a suitable seismic signature should be seen in 1996,ten years after acquisition of the first 3-D seismic survey. Acquisition of a monitoring 3-Dsurvey began, with the intent to bury hydrophones in a semipermanent installation forrepeat surveys over several years. The mechanics of this proved to be more difficult thananticipated, due to the highly mobile and unstable nature of the ocean bottom. Like manysimilar projects of that time, permanent sensor installation was not a success. Two yearslater, in 1998, a marine streamer 3-D was acquired by Geco over part of the field, and then4-D seismic observations could be made.

The initial Bay Marchand 3-D seismic survey was not designed to be a base for later4-D observations, and that created difficulties in making interpretations of time-lapseseismic effects. In some areas the data required time shifts, amplitude balancing, andphase corrections. But in many areas, a direct comparison of horizon slices from thedifferent surveys provided insight into current reservoir conditions, water movementand remaining hydrocarbon potential. Two examples are shown of water movementin the reservoirs during oil production. Both show heterogeneous sweep and bypassedoil potential. New drilling and completions then added to both the reserves and theproduction, as is shown in the following two examples.

The first example considers a fault block under oil production. The horizon slice of thereservoir from the 1986 3-D survey showed high amplitude remaining where wells AB, and C are producing oil (Figure 14-10-41, top panel). An additional observation well(D) was full of oil in 1986. However, repeat cased-hole logging showed that by 1999, thereservoir was swept significantly, and the water level in the well had risen. By 1999, thethree producing wells also were making significant water and not enough oil (Behrens

et al., 2001). A second 3-D seismic survey, in 1998, showed the seismic response to beconsistent with water encroachment in the wells (Figure 14-10-41, bottom panel). Thehigh-amplitude area revealing unproduced oil indicated that producers were drawingup the water front in this relatively low-gravity oil. However, the new survey alsoshowed a high-amplitude area directly between wells, suggesting uneven reservoirsweep and bypassed reserves. Follow-up drilling by Chevron proved that to be a correctinterpretation and led to completion of an additional horizontal development well, whichadded good production rates to the field.

A similar but more complex result was observed in clastics at the deeper 7600-ft levelThe repeat survey showed the oil sweep to be very uneven because of low-gravity oilplus the vertical and horizontal variability of reservoir facies (Figure 14-10-42). From 1986through 1998, wells G, H, and I produced significant volumes of oil. Wells G and H weremaking significant water cuts by 1998, and well I had watered out completely. Again, the

second seismic survey revealed bypassed oil reserves. Infill wells were drilled by Chevronand Energy Partners Ltd. in all three high-amplitude zones of the 1998 survey, provingbypassed reserves. Two were then put on stream, adding to production.

Advances in seismic technology have opened the door to new opportunities in theunderstanding of geologic complexity for Bay Marchand. As an example, the legacy1986 3-D data and the later 3-D seismic surveys were subjected to advanced inversiontechnology. The objective of such technology is to remove the wavelet from the seismic toreduce interference effects. With increased resolution from wavelet removal, the seismicdata revealed previously unrecognized boundaries caused by horizontal stratigraphic

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changes, especially in the predominantly deltaic environment of the majority of the fieldsreservoirs (Figure 14-10-43). This resulted in recognition of additional reserves in the fieldas stratigraphic traps and pinchouts, and in revelation of additional shallow reserves atthe top of the field, known as attic plays.

Following the success of higher resolution from inversion, more attention was directedto specialty acquisition for stratigraphic information. In 2004 and 2005, Bay Marchandwas the site of the first commercial-production use of the VectorSeis Ocean Bottom Cable

(OBC) acquisition using MEMS technology. MEMS (microelectromechanical systems) isthe integration of mechanical elements, sensors, actuators, and electronics on a commonsilicon substrate through microfabrication technology (Figure 14-10-44). A positiveindication was obtained from a value-of-information study (VOI) for ultra-sensitiverecording at very high frequency, and from the recording of traditional acoustic wavesplus additional recording of shear waves. New seismic data were acquired by GXT (ION)targeted solely at shallow reserves which had been obscured by imaging problems at thetop of the salt dome.

The top of the Bay Marchand field is the site of historical and present-day expulsion ofhydrocarbon fluids. The chimney of mobile hydrocarbon fluids invades lower-pressuregeologic formations, and near the surface this includes silty and shaly lithologies as wellas sands, resulting in a mlange of unstratified reflectors as seen by compressional (P)-waves (Figure 14-10-45a). Worldwide cases of shear (S)-wave recordings show that theycan result in successfully imaging the subsurface where P-waves have failed, because S-waves respond more to the rock matrix than to the fluids or gas.

A limited acquisition trial was conducted to image through the chimney at the topof the salt dome and also to obtain higher frequency on the adjacent flanks. Spatialacquisition sampling was approximately three times denser (12.5 x 6.3-m bins) than in thelegacy survey. The result was excellent P-wave data (Figure 14-10-45b). Far better faultdefinition and a consistent structural interpretation were now possible over portions ofthe area, and a valid top-salt reflection was revealed. Valid amplitude information showedthe character of stratigraphic changes horizontally, and it was possible to detect thepresence of gas migrating up specific faults. Unfortunately, the S-wave imaging has notbeen successful, due to difficulties in near-surface sampling density and the uncertainty inV

p/V

sratios.

There are geophysical technologies that have not yet been applied to the field. Examplesof these include seabed electromagnetic surveying, cross-borehole seismic and/orelectromagnetics, and multi-azimuth seismic, among others. Bay Marchand geoscientistsand reservoir engineers continually stay abreast of the potential for technology applicationand have the interest and support of the greater Chevron technology network. As goodgeophysical proposals are considered, they are subjected to review from value-of-information (VOI) analysis. This is appropriate, as geophysics is an expense and providessubsurface information it does not produce oil!

New geophysical initiatives moving forward today include technologies that havesucceeded elsewhere and appear to have application in Bay Marchand. Measuringamplitude variation at different angles of reflection (amplitude variation with offset, or

AVO) provides another measure of earth properties that can reveal additional changes instratigraphy and/or fluids. In 2006, a combined 3-D prestack data set was processed foradvanced AVO analysis and is just now being evaluated. Initial results are promising, asyet further delineation and development prospects are emerging.

Finally, Bay Marchand holds at least one more deep secret. The field has beendelineated, developed, and produced from sands on the top of the dome and on the flanksof the salt body, but there is also untested potential below the salt (Figure 14-10-46). Asis the case with many salt bodies in the Gulf of Mexico, the Bay Marchand dome mayhold reserves in traps that can only be visualized after depth migration, because imagingbecomes confused below complex salt bodies. As of this writing, a merged 3-D prestackdepth migration has been performed and the results are being evaluated (Figure 14-10-47).

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Part of the reason why seismic data clearly add high value in the Bay Marchand fieldis a combination of geologic complexity, a large number of producing reservoirs, and theusually favorable rock physics. With hundreds of reservoirs and more than 1200 wellsdrilled, the chances of seeing good conditions for seismic response are high. It should notbe expected that all reservoirs in the field or similar reservoirs worldwide will respondquite so well. Many of the reservoirs in Bay Marchand are difficult to image or do nothave favorable acoustic characteristics. What is true, however, is that the majority of

significant seismic technologies of the past 80 years have been successfully applied to thefield. In every case the geophysical investment has been found to be worthwhile, and theimpact on production and value creation have been directly measurable.

Bay Marchand is the field that has produced the most oil in the Gulf of Mexico forChevron. It is also the field that has produced a great number of geophysical-technologyadvances. Geophysics supported the field discovery, delineation, and production. Perhapsmore importantly, geophysics was directly involved in the revitalization of an extensivelydrilled and seemingly exhausted resource. Production decline was reversed and thensustained with seismic-technology advances in support of geologic interpretation andhigh-quality reservoir management. Bay Marchand stands out as an example of wiseapplication of advanced technology to manage the hard-won subsurface assets of thepetroleum industry. Every field deserves to be well operated, and seismic data can clearlyplay a role in that effort.

The authors wish to thank the management of Chevron North America Exploration andProduction, and of Chevron Energy Technology Company, for permission to publish thiswork, and the management of WesternGeco and GX Technology for permission to showthe seismic data. The authors also wish to thank the current and former members of theBay Marchand Asset Team for their contributions to the development of this extraordinaryfield. Special thanks go to Abby Hymel, Torin Edwards, and Philip Richardson for theirassistance in reviewing the paper and providing examples.

Abriel, W. L., P. S. Neale, J. S. Tissue, and R. M. Wright, 1991, Modern technology in anold area Bay Marchand revisited: The Leading Edge, v. 10, no. 6, p. 2135.

Behrens, R., P. Condon, W. Haworth, M. Bergeron, Z. Wang, and C. Ecker, 2001, 4-D

seismic monitoring of water influx at Bay Marchand: The practical use of 4-D seismicin an imperfect world: SPE paper 71329.Frey, M. G., and W. H. Grimes, 1970, Bay Marchand-Timbalier Bay-Caillou Island salt

complex, Louisiana, inM. T. Halbouty, ed., Geology of giant petroleum fields: AAPGMemoir 14, p. 277291.

Summary

Acknowledgments

References



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Fig. 14-10-1.The BayMarchand field is locateda few kilometers south ofthe Louisiana coast in theGulf of Mexico.

Fig. 14-10-2.A crosssection of the BayMarchand field. The fieldcomprises many differentaccumulations of oil andgas in different typesof traps. Most traps are

combinations of structureand stratigraphy.



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Fig. 14-10-3.The field lies in a structural trend characterizedby deep- seated salt piercement domes (a). Early in theexploration phase, this structural trend was recognized fromgravity data (b).

Fig. 14-10-4.Thediscovery in 1949

was preceded bytwelve unsuccessfulexploratory wells.

(a) (b)



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Fig. 14-10-5.Immediately afterthe discovery, three platformswere installed over the center ofthe salt dome. Directional wellswere drilled from the platformsto develop and produce thediscovered oil and gas.

Fig. 14-10-6.Immediately after discovery, thedepth and extent of the salt dome were confirmedby refraction seismic data. An exploration wellwas used as a source location at the center, andreceivers were placed on the ocean floor in aspoke and wheel pattern (a). The time recordingsof the refracted waves from the salt surface wereused to map the location of the dome (b).

(a)

(b)



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564

Fig. 14-10-7.Structure of top saltfrom the detailed refraction surveyof 1950. The accuracy of this maphas been confirmed after more thanfifty years of drilling and hundredsof well penetrations. A salt overhangon the east flank was correctlyrecognized and was confirmed inlater years with reflection seismic

data.

LEGEND

CONTOURS INTERPOLATED OR PROJECTED ONBASIS OF WELL CONTROL

- - - - - - - - - CONTOURS BELOW OVERHANGCALIFORNIA COMPANY PLATFORMALL CONTOURS ARE DRAWN ON DOMAL MATERIAL

CONTOUR ON DOMAL MATERIAL(REVISED INTERPRETATION BASED ON VELOCITY SURVEY

SHOT IN PLACID & UNION OF CA1. #1 ON DEC. 17, 1950)

REFRACTION SEISMIC SURVEY

FOR THE CALIFORNIA COMPANY

BAY MARCHAND DOMELAFOURCHE PARISH

LOUISIANA

SCALE 1=2000

MAP GRID: LAMBERT COORDINATE SYSTEM

SEISMIC SURVEY BY: McCOLLUM EXPLORATION CO.AUGUST, 1950

INTERPRETATION BY: ALEXANDER WOLF, CONSULTANTAPRIL 6, 1951



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565

Fig. 14-10-8.During the1950s, many platformswere installed northwestand southeast of thecenter of the dome. Alarge number of structuraland stratigraphicaccumulations weredeveloped.

Fig. 14-10-9.Duringthe 1960s, furtherdevelopment proceededdown the flank of thedome.



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Fig. 14-10-10.The daily production of thefield reached more than 80,000 barrels ofoil per day in the 1960s. During the nextdecade, in the 1970s, daily productionwent into significant decline.

Fig. 14-10-11.Reflection seismic data and digital processing inthe 1970s offered a substantial technological breakthrough. Usingthis type of data, it was possible to accurately interpolate structurebetween wells on the seismic profiles. In addition, reflection patternsand amplitudes were used to predict stratigraphic trends.



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567

Fig. 14-10-12.In the1970s, 2-D seismicreflection data wereacquired on anapproximately 500-mspacing, to supportdevelopment andproduction of the field.

Fig. 14-10-13.2-D seismicreflection data were usedto support specific infilldevelopment wells andwaterflood projects.



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568

Fig. 14-10-14.In 1986, a3-D seismic survey wasconducted to cover thefield for developmentand production support.Individual receivers wereplaced on the ocean floorat 220-foot intervals in twolines spaced 880 feet apart

(a). Airgun sources werefired at 110-foot intervalsalong line. When it wasnot possible to positionthe source boat at theplanned surface location,due to production facilities,placement of sources andreceivers was switched (b).The acquisition of the dataprovided perfect coveragefor every subsurface pointin the field.

(a)

(b)



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569

Fig. 14-10-15.Acquisitionof the 3-D data wascomplicated by numeroussurface obstacles, whichincluded over 100 platforms,two major transport pipelinesystems, collection anddistribution pipelines, andhigh-voltage power systems.

Operation of the oil fieldwas not interrupted and nodamage was sustained.

Fig. 14-10-16.East-west

seismic cross section fromthe 3-D data. Faults interactwith the salt dome to producesharp interfaces. Oil andgas are located in numerousstructural traps against faultsNumerous stratigraphic trapsare also located on the flanksof the dome.



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570

Fig. 14-10-17.A time sliceof the 3-D seismic datashows the angular natureof the faults interactingwith the salt-producingsharp corners.



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Fig. 14-10-18.Structure map of thetop salt just below the major producinginterval. Twenty-three wells establish thestructural trend.

Fig. 14-10-19.Time sliceof the 3-D survey at 1.5seconds over area ofFigure 14-10-18. Note theembayment in the centerof the figure. This wasnot recognized from thestructural analysis usingwell data.



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572

Fig. 14-10-21.Thestructural crosssection of A-A showsthe results of thedrilling of infill well 40and the discovery ofnew reserves.

Fig. 14-10-20.Seismicarbitrary line A-A asindicated on Figure14-10-19. Structuralanalysis from wellcorrelation of J-13 andL-1 was not sufficientto identify the potentialof reservoirs between

them. Well 40 wasproposed as an infillopportunity.



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573

Fig. 14-10-22.Oil and gasmap of the 8200 sand.The structural and fluidinterpretation is controlledby a 2-D seismic grid,40 well penetrations,production samples, andpressure measurements.

Fig. 14-10-23.Reinterpre-tation of the same areausing the same wellinformation but alsousing 3-D seismic data.Note the change in thefaults and location of fluid

compartments.



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574

Fig. 14-10-24.Seismiccross section from the 3-Ddata, showing the locationof the top and bottomof the CP-7 sandstonereservoir.

Fig. 14-10-25. Horizonslice of the CP-7 sand.High amplitudes areassociated with highreservoir quality. Theinterpretation of thehorizon slice is that the

thickest sand is locatedin a channel meanderingbetween two faults.



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575

Fig. 14-10-26. Structure and fluid mapof the 4475 sand. Prior to the newinterpretation from the 3-D survey, the faultblock was considered depleted.

Fig. 14-10-27.Horizonslice of the producing4475 sand. High-amplitude (red) seismic

response was interpretedto be bypassed oil. Newinfill wells were drilledand successfully put intoproduction.



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576

Fig. 14-10-28.Fluid andstructure map of theproducing FX reservoir.Water injection wasproposed for well G-3,to move more oil into theproducing wells 24 and25.

Fig. 14-10-29.A geologiccross section showingthe well logs of the FXreservoir.



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577

Fig. 14-10-30. Thearbitrary seismic line

associated with the crosssection in Figure 14-10-29. The high-amplitudereflections in the centerof the line are the FXreservoir.



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578

Fig. 14-10-32.Net-sand mapof the FX reservoir. This isgenerated from well controlplus the time thickness andamplitude of the seismic

data.

Fig. 14-10-31. Horizon sliceof the FX reservoir. Note thatall 3 wells in the reservoirare in the moderate (yellow)amplitude. Notice that theamplitude of the horizon slicebetween the wells is highlyvariable.



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579

Fig. 14-10-33. Flow-linereservoir simulation ofwater injected into wellG-3 and oil producedin wells 24 and 25. The

thicker portion of thereservoir between wellsG-3 and 25 shows a largerflow of water to move theoil, as indicated by thehigher density of the flowlines.

Fig. 14-10-34.Forecast productioncomparing reservoir models of constantthickness, derived from well data, and thevariable-thickness model, derived fromboth well and seismic data. In this case, thevariable reservoir model has a 28% higherrecoverable.



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580

Fig. 14-10-36.Map of theoutlines of several 3-Dsurveys that now cover theBay Marchand field.

Fig. 14-10-35. Productionof oil from the BayMarchand field for a 50-year interval from startup.The production decline inthe 1970s was reversedby field rejuvenation frominfill wells, horizontal wells,and improved waterflood.

This was accomplishedwith the subsurfaceknowledge provided from3-D seismic data.



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581

Fig. 14-10-37.Unmigrated seismic cross section composed of two of the 3-D surveys. Different acquisition and processingparameters cause the data to be poorly matched where they intersect.

Fig. 14-10-38. Seismic cross section from Figure 14-10-37, reprocessed. The two surveys were processed together to matchsignal to noise, time position, amplitude, and phase.



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582

Fig. 14-10-39.Horizon slice of a produced oil reservoir.This reservoir compartment was on production for manyyears prior to acquisition of the 3-D survey. Amplitudedid not correlate to the total reservoir thickness atthe wells. Low amplitudes in the reservoir center didrepresent depletion of the oil in the reservoir. A flowpathway can be observed between water injectors 1and 2 to the producing wells P1 and P2.

Fig. 14-10-40. Acoustic

response of different fluidsin reservoir sandstonesat approximately 8000-ftdepth. High-saturationoil sands respond withstrong negative acousticimpedance. Productionincreases the watersaturation and significantlyreduces the reflectionamplitude.



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Fig.

14-10-41.Horizonslicesfrom

anoil-producinghorizonin1986s

urvey(top)and1998survey

(bottom).ThereducedamplitudeareainthelowerpanelnearwellD

isconsistentwiththerepeat

case-holeproductionlogsshowingwaterinflux.Bypassedoilbetwee

nwellsAandBwasdrilledby

w e l l s E a n d F W e l l F w a s c o m p l e t e d a t h i g h p r o d u c t i o n r a t e s



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584

Fig.

14-10-42.Horizonslicess

imilartothoseofFigure14-10-41butforadeeper

reservoir,showingdetectionofloweredseismicamplitudeduetooilproductionand

waterinflow.BypassedoilwasdrilledinwellsJ,K,andLandthenp

utintoproduction.



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585

Fig.

14-10-43.Comparisonofseismicdataandinverteddata.Lowim

pedances

(yellow)intheinverteddataaresandstonesembeddedinshales.Theinverted

dataareeasiertointerpretbecauseindividualsandscanberecogn

ized

SeismicData

Sandsarerepresent

edby

overlyingtrough(ye

llow)

plusunderlyingpeak(black)

I

nvertedData

S

andsinyellow

c

hannelsystem

p

inchouttoleft



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586

Fig. 14-10-44.Survey parameters and photos of hardwareused in a high-resolution acquisition program for detectionof shallow reserves. Compressional (P)- and shear (S)-waves were recorded at very high and very low frequenciesusing microelectromechanical systems (MEMS).



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587

Fig.

14-10-45.ComparisonofP-waveseismiccrosssections

fromthe19863-Dseismicsurv

ey(a)andthe2004MEMS

high-resolution3-Dsurvey(b).

Improvementsareseenin

locationofthesaltinterface,sh

allowfaulting,definitionof

unconformities,anddirectdete

ctionofhydrocarbons.

3D

seismic

High-resolution

acquisitionandimaging

(a

)

(b)



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588

Fig.

14-10-46.3-Dtime-migratedseism

iccrosssectionof

theentireBayMarchandsaltdome.Th

edataarethought

toshowhighpotentialforsubsaltoilan

dgasreservoirs.

Fig.

14-10-47.3-Dprestackdepthmigratedcross

sectionshowingclea

rbasesalt.Subsaltreflectorsmay

comefrom

reservoirs

thatholdadditionalreserves

14c_value of geophysics in the production of bay marchand field

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