Subsalt Field Research Articles

Main Challenges and Strategies to Develop Santos Basin Sub-Salt Fields, Deep water Brazil

Abstract Santos basin of Brazil is a hot area of oil and gas exploration and development in the world. Many sub-salt oil fields have been discovered in recent years. The reservoirs are mainly composed of microbial carbonate rocks with strong heterogeneity, which has developed a variety of storage space types. The fluid is complex with high gas oil ratio and CO2 content. The re-injection of produced gas brings uncertainty to the production performance and the stability of facilities. The project investment is huge due to many factors such as deep-water, deep buried and far away from the coastline. The complexity of reservoir and high investment of project make the economic and effective development of reservoir full of great challenges. This paper describes the development strategies of Brazil’s sub-salt deep-water oilfield and the main successful methods to maximize recovery and profits under uncertain conditions. It includes the following three aspects: (1) abundant information acquisition to reduce the main uncertainties; (2) development plan with robustness and flexibility to deal with potential risks; (3) multidisciplinary comprehensive research to evaluate reservoir mode and development mode.

The northern Gulf of Mexico offshore super basin: Reservoirs, source rocks, seals, traps, and successes

The northern Gulf of Mexico federal offshore area easily qualifies as a super basin based upon estimated petroleum endowment of more than 100 BOE and cumulative production of 60 BOE. Like other super basins, it has multiple petroleum systems and stacked reservoirs. Examination of four key elements of these petroleum systems (reservoirs, source rocks, seals, and traps) yields important insights to the geologic processes that result in such an exceptional habitat for conventional hydrocarbons. The bulk of hydrocarbon resources in federal offshore waters is in Cenozoic sandstone reservoirs such as the Paleogene Wilcox reservoir of deep-water subsalt areas. Overall, Cenozoic sandstone reservoirs in both suprasalt and subsalt fields yield the highest flow rates and cumulative production volumes. Notable is the recent addition of the deep-water Jurassic Norphlet sandstone play, the newest and second largest by ultimately technically recoverable resources. Overall, Gulf of Mexico reservoirs are diverse, formed in paleoenvironments ranging from aeolian to deep water. Powering this super basin are three primary marine source rocks centered in the Oxfordian, Tithonian, and Cenomanian–Turonian Stages. These source rock intervals commonly act as top seals, but other Neogene and Mesozoic shales and even carbonate mudstones are also important trap-sealing elements, as proven by analytical work and downhole pressure measurements. The extensive salt distribution and relatively late Cenozoic burial delayed source rock maturation and migration until the culmination of trap formation in many areas. High rates of Cenozoic deposition on a mobile salt substrate also generated a myriad of salt tectonic structures, ranging from simple diapiric closures and extensional fault traps to complex subsalt configurations such as salt-cored compressional anticlines, salt-cutoff traps, and bucket weld traps. Exploration success in the past 20 yr is a direct result of improved seismic imaging around and below salt, as well as advances in drilling, completing, and producing wells and fields.

Evaluation and correction of sources of 4D noise using modeled ocean-bottom-node data

Ocean-bottom-node (OBN) data are being used successfully in the deepwater environment to acquire time-lapse surveys due to their low 4D noise level. To help maximize the benefits of using such data, we built an acoustic model based on a deepwater subsalt field from the Gulf of Mexico. We generated synthetic base and monitor data using a realistic acquisition geometry and a laterally variable, random water-velocity layer. This study focuses on investigating a number of sources of time-lapse noise, including water-velocity variations, source and receiver repeatability, and position accuracy, and on evaluating ways to correct for these errors during processing. Results indicate that variable water velocities, if not corrected for during processing, produce the majority of residual 4D noise observed on the difference images. With currently achievable node placement accuracy, repeatability is fairly good and produces the smallest amount of noise. Sources, which are the least repeatable, produce almost three times the amount of noise compared to nodes in our experiment. We applied a similar processing workflow to the up- and downgoing wavefields and imaged both types of data using one-way and two-way wave-equation-migration techniques. In this particular synthetic example, image quality and 4D noise level were similar in the extra-salt area on both processed up- and downgoing images, but both measures in the subsalt were much better on the upgoing data.

Improving the greater K2 area subsalt imaging with advanced seismic acquisition, model building, and imaging technologies — A Gulf of Mexico case study

Subsalt imaging has proven challenging in part because of the complex geometries of the salt canopies, which can yield highly variable illumination on subsalt reflectors. The resulting complexity of the seismic wavefields has also challenged traditional velocity-model-building tools and migration algorithms. A case study for the K2 field illustrates how improved seismic data in the form of long-offset, full-azimuth acquisition and more advanced model building and imaging tools have substantially enhanced the imaging quality of this major subsalt field. The higher fold and more complete azimuthal coverage afforded by the full-azimuth coil data improved the effectiveness of the combined tomographic and full-waveform inversion approach for velocity-model building. Utilization of TTI RTM migration algorithms provided further benefits not only for better delineation of the salt geometry during model building but also in delivering superior final image volumes relative to that which could be provided by less robust algorithms, such as Kirchhoff, beam, and one-way wave equation.

Subsalt Imaging in the Kaombo Development, Angola

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 24132, ’Kaombo, From Exploration Toward Development: A Decade of Progress in Subsalt Imaging,’ by V. Martin, A. Douillard, L. Lemaistre, V. Clerget, and C. Gerea, Total E&P, prepared for the 2013 Offshore Technology Conference, Houston, 6-9 May. The paper has not been peer reviewed. Copyright 2013 Offshore Technology Conference. Reproduced by permission. Kaombo is a multifield development on Block 32 in Angola. Approximately two-thirds of the block is covered with a salt canopy that strongly degrades visibility, which prevented a good estimation of the resources and their distribution in several subsalt areas during the initial years of exploration. However, the last decade has seen a dramatic improvement in seismic processing, enabled by the increase in high-performance computing (HPC) capabilities. Through examples of subsalt fields of the Kaombo project, we show how new techniques have had a positive effect. Introduction In the Kaombo development, Tertiary turbiditic reservoirs are located below the salt canopy. Unlike other blocks of the lower Congo basin that are more proximal to the shore, a shallow canopy of complex-shaped salt bodies below the sea surface covers much of the block. The salt bodies create strong lateral seismic-velocity variations that are highly detrimental to classical time-processing approaches. Thus, prospect-maturation work during the early days of this block (1999 to 2001) was focused on targets outside of the salt influence. While its application was initially restricted to a few areas for cost reasons, prestack depth migration (PSDM) rapidly became the standard exploration tool on the block during the period from 2002 to 2004. These first stages of subsalt explorations involved Kirchhoff and common azimuth wave-equation migrations, because of their relatively low computational cost, applied to a 3D narrow-azimuth data set. Migrations were performed by use of simple isotropic velocity models and a priori salt models where the salt geometry could not be assessed with certainty. The quality of the images was improved compared with standard time processing, but some work remained to increase the probability of success of subsalt prospects sufficiently to drill these prospects. Application of depth-imaging techniques thus allowed a glance at the subsalt potential of the block. Depth imaging is a technique that takes advantage of modeling the propagation of waves in the space domain. Images are functions of data and a seismic-velocity model. In environments such as Block 32, complexity of the velocity model and uneven illumination of the subsurface by the data are severe challenges. The strategy of image improvement is therefore limited by three factors: the capability to accurately describe subsurface propagation parameters (velocity model), the capability to accurately model the wave propagation through the subsurface given the complexity level of the subsurface models (migration algorithms), and the capability to compensate for uneven illumination (acquisition). Progress in subsalt imaging can be achieved by improving methods in these three domains, which are unlocked by the increase of HPC capabilities and new acquisition designs.

Kinematic linkage between minibasin welds and extreme overpressure in the deepwater Gulf of Mexico

A geopressure interpretation technique known as the seismic velocity method is a common workflow in which shale compaction functions are characterized at offset control wells, matched to interval seismic velocities, and then used to predictively calculate geopressure away from well control. The seismic velocity method is used to interpret the expected geopressure profile at the Deep Blue subsalt exploration well in Green Canyon 723 in the deep water Gulf of Mexico. The Deep Blue prospect is distinct from other prospects in the play fairway in that the prospective section is overlain by a salt withdrawal minibasin, whereas the offsetting fields are positioned either along the flanks of minibasins or under a thick allochthonous salt canopy. Predrill geopressure interpretations using numerous tomographic imaging velocity data sets shows a large degree of consistency with the magnitude of geopressure encountered in offsetting supra salt and subsalt fields. Results from the Deep Blue 1 exploration well indicate the predrill geopressure interpretation from interval seismic velocities failed to anticipate the extreme degree overpressure encountered in the subsalt section of the well due to poor deep velocity resolution and an “unloaded” compaction signature. The magnitude of overpressure in the primary section is attributed to the emplacement of an unconformable halokinetic sequence over the primary subsalt basin. An interpretive paradigm is described in which the Deep Blue pressure cell is created through two halokinetic episodes: (1) rapid progradation of a salt canopy followed by (2) subsequent salt withdrawal and emplacement of an overlying minibasin. The linkage between halokinetic sequences, burial history, and the development of overpressure can be used to predictively characterize subsalt geopressure environments.

Subsalt pressure prediction in the Miocene Mad Dog field, Gulf of Mexico

Sandstone pressures follow the hydrostatic gradient in Miocene strata of the Mad Dog field, deep-water Gulf of Mexico, whereas pore pressures in the adjacent mudstones track a trend from well to well that can be approximated by the total vertical stress gradient. The sandstone pressures within these strata are everywhere less than the bounding mudstone pore pressures, and the difference between them is proportional to the total vertical stress. The mudstone pressure is predicted from its porosity with an exponential porosity-versus-vertical effective stress relationship, where porosity is interpreted from wireline velocity. Sonic velocities in mudstones bounding the regional sandstones fall within a narrow range throughout the field from which we interpret their vertical effective stresses can be approximated as constant. We show how to predict sandstone and mudstone pore pressure in any offset well at Mad Dog given knowledge of the local total vertical stress. At Mad Dog, the approach is complicated by the extraordinary lateral changes in total vertical stress that are caused by changing bathymetry and the presence or absence of salt. A similar approach can be used in other subsalt fields. We suggest that pore pressures within mudstones can be systematically different from those of the nearby sandstones, and that this difference can be predicted. Well programs must ensure that the borehole pressure is not too low, which results in borehole closure in the mudstone intervals, and not too high, which can result in lost circulation to the reservoir intervals.

Ultradeepwater-Subsalt-Reservoir Characterization: Integrated Multiscenario Development Planning

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 142280, ’Ultradeepwater- Subsalt-Reservoir Characterization: An Integrated Multiscenario Approach for Development Planning,’ by Olivier Pippi, SPE, Statoil ASA (formerly with BP plc), Mike Mayall, Mike Chandler, SPE, Tim Dodd, Paul Reid, and Paul Taylor, BP plc, prepared for the 2011 SPE Europec/EAGE Annual Conference and Exhibition, Vienna, Austria, 23-26 May. The paper has not been peer reviewed. Subsea development of clustered deepwater subsalt fields is challenging, technically and economically. With the high cost of appraisal wells, the industry tends to rely on seismic technology, pushing the limits of imaging and characterizing the reservoir by use of seismic attributes. A fully integrated approach that uses all available data should be followed to describe the uncertainty fully and to make an optimized business decision. This work shows a systematic method to integrate information available from a limited data set to validate the description of the field and to perform a full risk and uncertainty analysis supporting the field-development strategy. Introduction Many exploration plays in deepwater basins around the world involve structural closures associated with stratigraphic-trapping elements that are above or against salt diapirs or canopies. Below these often-large salt bodies, seismic imaging can be impaired significantly, which makes the crest of the structure particularly complicated to map. Updip volumes that are close to the salt can be difficult to describe with confidence, yielding large uncertainty about hydrocarbon volumes in place. Reservoir faulting induced by the movement of the salt over geological time introduces significant structural complexity. This complexity adds to common stratigraphic and depositional complexity of deepwater reservoirs deposited in turbidite slope settings. Deepwater turbidite reservoirs can be large erosional channels (typically 1 to 3 km wide and 50 to 200 m thick) or can be sheet-like sands (typically 1 to 5 km wide and 5 to 30 m thick) with various degrees of channel amalgamation. Each type of reservoir poses specific development challenges in terms of continuity and connectivity. Multiscenario Risk and Uncertainty Analysis Given the structural complexity of the field, the wide range of oil-in-place estimates results in making risk and uncertainty analysis difficult to address at the same time. A project close to sanction would have a firmer resources-in-place definition before making a decision. Alternatively, the decision would have flexibility to be phased in over a certain time as new production data become available.

Time-lapse 3D VSP using permanent receivers in a flowing well in the deepwater Gulf of Mexico

The vision of smart wells permanently instrumented with geophones has existed for some time. Such installations would enable opportunities for frequent reservoir monitoring, high-resolution 3D VSP imaging, and illumination of difficult areas. For many subsalt fields, 3D VSPs acquired in such wells may be the best option to illuminate and monitor reservoirs without the need to stop production or enter a well. However, this technology is not yet widely applied, nor perhaps proven.

Comments: Brazil's New Finds

Editor's column For an example of one of the new breed of successful national oil companies, look no further than Petrobras. Well known for technology expertise and innovation—the company has won two Offshore Technology Conference (OTC) awards for technical achievement—the Brazilian company is now making news for what could be some of the biggest oil discoveries in years. Petrobras' Tupi discovery, located more than 150 miles in deep water off the Brazilian coast, has estimated recoverable reserves of between 5 and 8 billion bbl. That would make it one of the most significant finds in the past 20 years, according to analysts Wood Mackenzie, rivaling the 2000 Kashagan discovery in Kazakhstan and surpassing the largest deepwater finds, including those in the US Gulf of Mexico and offshore west Africa. Initial production of 100,000 BOPD could begin in 2010. Petrobras has announced a series of oil discoveries in the Santos basin in recent months, including the natural gas field Jupiter and the subsalt field Carioca, which has drawn considerable speculation about its size. At this year's OTC, Petrobras Chief Executive Officer Jose Sergio Gabrielli, while acknowledging the importance of the deepwater discoveries, would not speculate on potential reserve figures. If the promise of Tupi holds, Brazil would boost its reserves by 50% and join the ranks of the world's most significant producers. Already there is speculation that Brazil might eventually join OPEC. Petrobras' rise has been steady since it was partially privatized by the Brazilian government in the late 1990s. The country only recently became energy self-sufficient and now produces more than 2 million BOPD, almost 90% of it offshore. The company expects output to rise to 3 million BOPD by 2012 and 4 million BOPD by 2015. Petrobras believes that Tupi may be just part of a huge subsalt cluster extending hundreds of miles along the Brazilian coast. Brazil's new oil finds will not be easy, or inexpensive, to develop. Although Brazil is considered a global leader in offshore development, the Tupi basin is located under 7,000 ft of water and then under 9,200 ft of shale and salt. Seismic imaging will be difficult and may hamper accurate estimation of reserves, and drilling challenges are common in subsalt. With regard to the Carioca area, Petrobras is at the beginning of its evaluation plan and will not have precise volume estimation until after finishing the plan. The company's success could put a strain on already tight equipment and talent markets. Petrobras, which already has leased most of world fleet of vessels for deepwater drilling, plans to lease more and also hire thousands of upstream personnel as it creates a new division for subsalt drilling.

Overview: Wellbore Integrity, Sand Management, and Frac Pack (September 2006)

Geomechanics tools are used to forecast, and then gauge, asset performance over time. Wellbore integrity, sand management, and frac-pack engineering design and execution practices are linked by characterizing the geological section in terms of rock mechanical properties. Often, seemingly unrelated events that can plague high-risk, high-cost developments can be understood best when the geological environment, the geology and geophysics, is described as an engineering material (i.e., the rock mechanical properties that include formation strength and stress). A consistent characterization of formation stress and strength with the geological structure, lithology, and seismic attributes used to recognize the prospect ensures that the explorationists' vision is linked to the well engineers' design. Further, a consistent mechanical-property model for the field can be used to create a full-cycle asset-development plan from appraisal through abandonment, helping to reduce the risk of missed future opportunities resulting from well-systems-design constraints. Two examples come to mind.Reservoir-pressure depletion and subsidence can affect borehole stability to the extent that complex well designs are necessary to exploit the asset fully. Well placement depends on the subsiding reservoir section and on the reaction of the overlying geological section that must be drilled through to reach the reservoir.Sanding-potential risk usually increases with depletion. For compartmentalized reservoirs with varying depletion schedules, sand-risk mitigation often leads to one-size-fits-all completions that usually result in sand control. This method can limit re-entry options and decrease recovery. An accurate forecast of sanding tendencies for individual reservoirs, including the field production-management practices that affect sanding, can result in a more selective fit-for-purpose approach to completion design. For land-based operations, the consequences of well complexity may be addressed more easily; the downside is a poor estimate of field recovery that can either reduce opportunities for outlying prospects or, in the worst case, cause the asset to seem uneconomic. For major-capital projects such as deepwater subsalt fields, the capital outlays are immense, with single wells costing U.S. $100 million. For these deepwater projects, it is required that fewer wells produce reliably for longer periods of time. Well engineers need to get it right the first time. Wellbore Integrity, Sand Management, and Frac Pack additional reading available at the SPE eLibrary: www.spe.org SPE 95715 "Prediction of Sand-Production Rate in Oil and Gas Reservoirs: Field Validation and Practical Use" by P.J. van den Hoek, SPE, Shell Intl. E&P B.V., et al. SPE 98252 "Prediction of Sanding Using Oriented Perforations in a Deviated Well, and Validation in the Field" by I. Palmer, Higgs Technologies, et al. SPE 95514 "Evolution of Frac-Pack Design, Modeling, and Execution in the Ceiba Field, Equatorial Guinea" by C.L. Cipolla, Pinnacle Technologies, et al.

Prospecting and Developing Carbonate Reservoirs Under Excessive Pressures in Fields of PreCaspian Depression Taken as an Example: ABSTRACT

All large sub-salt hydrocarbon fields of the PreCaspian depression are connected with carbonate reservoirs and are characterized by abnormally high reservoir pressures of different origin. Exploratory drilling in fields under excessive pressures is very much complicated. To reduce the probability of disastrous absorptions and blowouts there has been developed special drilling-in technology with constant bottom-hole pressure control. To avoid fractures healing, to provide hydrocarbon phase state control, and to achieve maximum oil recovery there has been worked out a new technology of oil field development. According to this technology oil should be recovered first from the lower peripheral parts of the pool. This technology (taking into account the abnormally high reservoir pressures) provides gradual decreasing of reservoir pressure in the process of field development.

Mahogany: Seismic Technology Leading to the First Economic Subsalt Field: ABSTRACT

Mahogany: Seismic Technology Leading to the First Economic Subsalt Field: ABSTRACT