Pre-stack HTI Velocity Variation with Azimuth (VVAZ) and Amplitude Variation with Azimuth (AVAZ) are employed to locate open fracture networks at the Wolfcamp by detecting changes in azimuthal moveout and amplitudes caused by long, narrow bands of fractures associated with seismically mapped shallow graben features (Cook, McKee and Bjorlie 2019). Vertical fracturing within the Wolfcamp located beneath graben features mapped at the Lamar limestone horizon have demonstrated a fracture stimulation connection to excessive extraneous water and H2S in Wolfcamp horizontal wells within the Reeves County portion of the Delaware Basin. The working model assumes the shallow grabens are the result of middle-late Tertiary tectonic extension with faulting terminating at various depths: often directly beneath the Lamar limestone, but sometimes into the Bone Spring and even the Wolfcamp.
Frac gradient data was spatially referenced by frac stage for 31 horizontal Wolfcamp wells located within a 290 square mile 3D dataset. Low frac gradients are observed for 11 of the 31 wells. Low frac gradients are defined as greater than −0.1 psi/ft departure from the individual well frac gradient trend. All of the 11 low frac gradient wells produced elevated levels of H2S and excessive water in quantities that had severe negative economic impact and, in several cases, significantly reduced hydrocarbon deliverability. The low frac gradient stages of all low frac gradient wells is aligned beneath the shallow graben features.
There are 9 horizontal Wolfcamp wells that crossed beneath the shallow graben features that did not record low frac gradients and did not produce extraneous water or elevated levels of H2S. Another 11 wells were drilled between the shallow graben features and did not record low frac gradients or excessive water or elevated H2S.
Seismic attributes were used to map the lateral and vertical extents beneath the shallow graben features. However, there remains a great deal of uncertainty in determining the degree of vertical faulting or fracturing beneath the shallow graben features.
Quantitative structural geology techniques can be used in conjunction with seismic data to define fault locations and geometry to reduce risk when planning horizontal wells. Unconventional plays in the past decade focus on basins characterized by largely horizontal stratigraphy and minimal faulting. However, even basins with minimal structure contain small-scale faults that pose unique risks to horizontal drilling. A fault with 100’ of throw or less can present well-bore stability issues due to natural fracturing and rock strength contrasts across faults. Seismic data can image these faults but because of their subdued nature, reliably interpreting their geometry and understanding the associated drilling risks can be difficult.
We present case studies examining seismic sections from the Denver basin where horizontal wells intercept small-scale normal faults. These faults are visible on the seismic sections where they cut across the Niobrara at 30 – 45°. Wells that pass above, below, or intersect the faults at high angles are generally drilled and completed without issue. At deeper levels, wells intersected the same faults at very low angles (where fault dips < 30°) and experienced drilling and completion issues. The transition from steep fault dips within the Niobrara to low fault dips at deeper levels is not well resolved in the seismic sections but clearly represents a drilling hazard that should be considered.
The geometry of the faults can be estimated using structural forward modeling and area-depth-strain (ADS) analysis. These established structural geology methods quantitatively relate seismically-imaged fold shape and horizon displacements to the underlying fault geometry. We use these methods to compute the deep fault geometry from the seismically observed folding of the Niobrara formation. We demonstrate that the wellbore collapse was related to fault angle and for a shorter lateral distance. This strongly suggests that the listric bends in these faults is a high-risk zone.
Arisandy, Mellinda (PETRONAS Carigali Indonesia Operations) | Mazied, Miftah (PETRONAS Carigali Indonesia Operations) | Putra, Bayu P (PETRONAS Carigali Indonesia Operations) | Yogapurana, Erik (PETRONAS Carigali Indonesia Operations) | B Mohd Idris, Jamin Jamil (PETRONAS Carigali Indonesia Operations) | Darmawan, Hendra I. (PETRONAS Carigali Kuala Lumpur)
This paper describes geochemistry analysis, hydrocarbon charge and entrapment model for prolific "MA" Block in the West Natuna Basin. Even though the area is currently at a mature exploration stage, the behaviour of hydrocarbon distribution in the area is still poorly understood and the link between discovered hydrocarbon and possible kitchens is still unknown. This study is an attempt to understand hydrocarbon expulsion, charging and entrapment in "MA" Block to de-risk further exploration efforts.
Several localized inverted half-grabens were identified through seismic interpretation. Nearby wells were then selected in evaluating source rock quality and maturity. In order to determine hydrocarbon expulsion model, 1D-3D burial history and thermal maturity models were constructed using integration of source rock and fluids geochemistry, temperature, seismic, and well data. Hydrocarbon charge and entrapment models were then simulated using 3D basin modeling software and calibrated with existing proven accumulation to produce a risked understanding of hydrocarbon distribution in the study area.
This study suggests that the most possible source rocks are the Late Eocene and Oligocene shales of Lama Formation and Lower Gabus Formations. Both source rocks are indicated by type I & type III kerogen. Lama source rock was confined in the initial grabens and post mature in deep paleo-grabens. This study confirmed that charging is derived from four (4) kitchen areas: Anoa, Gajah, Kakap, and Kambing grabens. The oil samples from "MA" Block indicated lacustrine facies. Rock geochemistry analysis portrayed oil-prone and gas-prone source rock.
In general, hydrocarbon was migrated from the southeastern area (Kambing graben) and southwestern area (Gajah graben). Hydrocarbon was later on accumulated in the nearest structural entrapments (anticlines). In the deep grabens (Kakap and Kambing), the hydrocarbon expulsion was starting as early as 37 Ma and 31 Ma, respectively, while in shallow graben (Anoa) the expulsion was starting at 29 Ma. The earliest structural trap commenced at 21 Ma, aligned with the initial compressional regime that was affecting the West Natuna Basin. Notable accumulative erosion in Miocene was nearly 1000 m at inverted structures, by which partly removed regional seal and reduced reservoir effectiveness. Significant yet-to-find hydrocarbon is predicted to be concentrated in the Anoa, Kakap, and Northeast Kambing area.
Amplitude attenuation and phase distortion of seismic data are byproducts of the Earth’s anelasticity (Q). These effects are exacerbated under regions of anomalously high absorption, such as shallow gas, causing uneven image illumination and migration artifacts. We present a case study from the Northern Viking Graben in the Norwegian North Sea where we utilize single-iteration least-squares visco-acoustic prestack depth migration (Q-LSPSDM) to produce a stable Q-compensated image. The migration used high-resolution p-wave velocity and attenuation models, derived from visco-acoustic full-waveform inversion (QFWI). We show this workflow compensates locally for amplitude loss, eliminates the need for a Q-compensation amplitude gain limit, and enhances illumination, event coherency and AVO attributes, while reducing noise.
Presentation Date: Wednesday, October 17, 2018
Start Time: 8:30:00 AM
Location: 207A (Anaheim Convention Center)
Presentation Type: Oral
"Fit like!" Thankfully, Aberdonians are so courteous that they will quickly recognize that you are from out of town and will greet you with the more common: "How are you doing?" However, when you explore the city, be prepared to listen to a combination of Scottish slang and Doric dialect, typical of the northeast of Scotland. It will make you think that your English is a rare and forgotten language. Nonetheless, Aberdeen has not escaped from the globalization phenomenon and praises itself for being a multicultural and cosmopolitan city, where English is spoken with a wide variety of accents from all possible backgrounds. Here, people with diverse languages, origins, and religions, but with a common passion for excellence and good work, will quickly integrate you into the community and make you feel at home.
Gonzalez, Walter (Halliburton) | Sigismondi, Mario (YPF) | Jacome, Maria (Humber College Institute of Technology and Advanced Learning) | Izarra, Carlos (Geotech Ltd) | Graterol, Victor (VRG Geofisica SAS)
Aeromagnetic data are used to describe the basement in the Espino Graben, Eastern Venezuela sedimentary basin. In this case, the magnetic characterization has an important role that the interpreter has as a tool to understanding the regional structural geometry of this basin, not only to add seismic interpretation, but also because the comprehension at geodynamic-scale: effectively map outlines of magnetic sources are used to characterize the internal structure of the domains and to aid in their delineation. In this paper, we used SPI and AS methods show the edge locations, depths, and dips. The basement domain map was deriving from geometric attributes like total horizontal gradients and Gaussian curvature. Analysis of previously interpretations and published maps were used to formulate the concept of magnetic domains in a geodynamic framework.
Presentation Date: Monday, September 25, 2017
Start Time: 3:55 PM
Location: Exhibit Hall C/D
Presentation Type: POSTER
Zhang, Quincy (TGS) | Rodriguez, Gary (TGS) | Xun, Hao (TGS) | Bate, Duncan (TGS) | Keay, James (TGS) | Hudec, Michael (University of Texas-Austin, Bureau of Economic Geology) | Watson, Jonathan (Bridgeporth Ltd.)
Seaward-dipping reflectors (SDRs) represent flood basalts rapidly extruded during either rifting or initially subaerial sea-floor spreading (Jackson et al., 2000). Where high-quality geophysical data is not available, SDRs can be easily confused with a half graben, when both have reflections dipping seaward and both are near to the Continent-Ocean Boundary (COB). Differentiating SDRs and a half graben would have a huge impact to hydrocarbon exploration – a half graben in a rift basin is one of the major exploration targets but SDRs usually indicate that there is no exploration potential. We investigate a high-resolution 3D dataset in the Campos Basin, reprocess the dataset with gravity constraint and interpret a presalt graben system where previous workers interpret as SDRs.
In this paper we present Methodology for reprocessing Offshore Brazil Olho de Boi 3D survey acquired near the COB; Salt modeling; Gravity modeling and gravity constrained presalt velocity update; Reinterpretation of the presalt reflectors.
Methodology for reprocessing Offshore Brazil Olho de Boi 3D survey acquired near the COB;
Gravity modeling and gravity constrained presalt velocity update;
Reinterpretation of the presalt reflectors.
The reprocessing workflow is specially designed to image the presalt section. The interpretation based on the new 3D image, gravity inversion and borehole correlation suggests a large graben system in the center of the 3D survey. The improved presalt seismic images and the new interpretation of presalt graben systems will greatly help explorationists to analyze presalt sediment architecture and petroleum systems.
Presentation Date: Tuesday, September 26, 2017
Start Time: 4:20 PM
Presentation Type: ORAL
The uncertainties of overpressure estimation are among the major challenges to the development of deep and hot reservoirs in many sedimentary basins especially with regards to drilling safety and well economics. However, because of the anticipated huge economic benefits of HPHT geological environments, stakeholders in the oil and gas industry consistently seek to have a good understanding of subsurface pressure systems in order to promote safe and sustainable investments therein. Accordingly, information is required to improve the regional knowledge of geopressures and for the calibration of functions aimed at optimising pre-drill pore pressure estimates for future wells. The Central North Sea, with its vast number of HPHT wells, pressure data, drilling information and documented operational experiences in exploration, drilling, development and production activities stands in a good stead as a "geopressure laboratory" for the fine-tuning of pore pressure prediction concepts, improvement of current geopressure practices and ultimately guide investment and operational decisions in the unexplored areas of the basin itself and elsewhere as geological realities could permit. For this reason, this study utilised downhole pressure-related data and wireline logs to evaluate the pressure regimes in the Central North Sea. The approach involved the quantification of overpressures using standard pore pressure prediction methods that make use of the density and velocity logs of mudstones. The results show that the estimated pore pressure profiles are consistent with measured pressure data in the Cenozoic formations, which makes it reasonable to assume that disequilibrium compaction is the cause of overpressure in this shallow section of the wells. Going deeper into the wells, within the sub-Chalk section, typical calibration parameters from log data could not be used to achieve reliable estimates of overpressures as was the case in the Cenozoic section. Remarkably, while it is possible to adjust the Eaton exponents in order to match estimates with measured data, a wide range of exponent values of between 4.0 and 7.0 is however required. The implication is that there is no systematic variation of the Eaton exponents with the amount of overpressure or depth of burial of the sub-Chalk strata.
In total, some 60 wells have been drilled onshore and less than 10 offshore Somalia*, none of which in deep water. Several prospective basins remain undrilled, such as the offshore Jubba and Mid Somali High basins and the onshore Odewayne basin. In view of the gas discoveries offshore Mozambique and Tanzania, and also of encouraging results offshore Kenya (sub-commercial oil discovery Sunbird-1) and in Madagascar, the Somalian offshore and onshore basins were re-evaluated.
As to the Somali onshore basins, the extension of the Yemeni Jurassic and Cretaceous rifts into Somalia highlights their prospectivity. Seeps abound (Odewayne and Nogal basins) and some wells encountered good shows. Late Jurassic and Upper Cretaceous marine shales are source rock candidates. Gas in the area of Mogadishu may be associated with the Early Triassic Bokh Fm. source rock. Seeps in western Somalia are rare, and may result either from long-distance migration out of the Calub Graben or from locally mature Lower Cretaceous or Upper Jurassic.
We establish an inventory of proven and possible source rock occurences in Somalia by integrating publicly available data on slicks and seeps, geological and gravity maps, literature data, well data and geological information from adjoining basins. Our data indicate that in the Somali part of the Gulf of Aden, high heat-flow may critically affect the Late Jurassic source rock. However, Late Cretaceous or even Eocene sources may be locally oil-mature.
The presence of source rocks on the Somali Indian Ocean margin remains presently speculative. Abundance of slicks in the area south of Mogadishu may not relate to hydrocarbons. Of more interest are reported isolated slicks further to the north, in deeper waters of the Mogadishu and Mid-Somalia High Basins. These slicks may be related to Lower/Mid-Jurassic, Late Jurassic, Late Cretaceous or Eocene sources.
Analysis of onshore seeps in northern Somalia (Nogal, Daroor, Odewayne basins), integrated with seismic data, will allow to determine the origin of these oils and an assessment of the size of prospective kitchen areas. In the offshore, 3D-Basin-modelling will be required to determine which areas are prospective for gas or, especially, for oil.