Paleogeographic maps provide clear, concise pictures of the evolving complex geologic events of Western North America. Time slices are selected to show critical stages in the geologic history thereby providing a continuous view of the evolution of the region and clearly showing sequences of paleogeography and paleotectonics. The maps are particularly effective in demonstrating the geometry and history of terrane accretion and the affects of accretionary events on the growth of Western North America from Devonian to Present. The maps are also powerful tools for comparing varying or contrasting models of various terrane-accretion events and for showing cause and effect across broad geologic provinces. Other maps (isopach, paleogeology, facies, paleocurrent, etc.) can be used in conjunction with paleogeographic maps to further explain the geologic history.

The models presented here are derived and modified from the geologic literature. Data is plotted on basemaps and paleogeography is cloned from digital elevation maps to match the inferred distribution of landforms at given times and places. The paleogeography is shown in palinspastic restoration with reference to present political boundaries. The maps are finished in a fashion to show how paleogeography might have appeared as if seen from space. Colors suggest paleovegetation and inferred paleoclimate. Water depths are shown in shades of blue from evidence presented in the literature and presumed modern analogs. Although maps are assigned a specific geologic age, ranges are given to suggest the interval for which the maps are valid. The resulting series of paleogeographic maps provides a coherent picture of the geologic and tectonic history of Western North America that respects known and inferred geologic rates and geodynamic models.

Deep-marine reservoirs form some of the most attractive targets in many mature and frontier basins. Determining the distribution and geometry of these reservoirs, especially within tectonically-active settings, remains a major challenge, however, principally due to the complex interaction of a variety of extra- and intra-basinal controls (i.e. tectonics, climate, sea-level, etc). In this talk I use 3D seismic reflection, well and core data to provide a regional synthesis of the subsurface expression of a series of tectonically-controlled, deep-marine reservoirs that are developed along the western Norwegian margin. I will also outline the key controls on the deposition of these reservoirs and illustrate the key trapping styles.

Turbidite sandstones represent the best reservoirs; in core, individual beds are up to a few metres thick, but amalgamated units up to several tens of metres thick are common. Sandy-mudstone debrites are observed, but they are of poor reservoir quality and may form barriers or baffles to fluid flow. Synthetic seismograms indicate that sandstone-dominated deposits are expressed on seismic data as packages of high-amplitude reflections. Amplitude mapping indicates that 11 slope fans are recognised and that these were fed by sediment routed through upper slope canyons incised into the eastern basin margin. These fans are either ponded behind or overstep intra-basin highs; the key trapping styles are: (i) stratigraphic, and related to up-dip pinch-out of the fans into slope mudstones; or (ii) structural, and related to differential compaction-related drape of fans across underlying fault blocks.

The areal extent of the onshore drainage catchments that supplied sediment to the fans has been estimated based on scaling relationships derived from modern source-to-sink systems. The results of our study suggest that the Turonian fans were sourced by drainage catchments that were up to 2200 km2 and which extended up to 140 km from the shoreline. The estimated inboard extent of the catchments correlates to the innermost structures of a large fault complex, which is thought to have defined the position of the regional drainage divide in this region since the Devonian. I suggest that increased sediment supply to the Turonian fan systems reflect tectonic rejuvenation of the landscape, rather than eustatic sea-level or climate fluctuations. The duration of fan deposition is thus interpreted to reflect the “relaxation time” of the landscape following tectonic perturbation, and fan system retrogradation and final abandonment is interpreted to reflect the eventual depletion of the onshore sediment source. Future exploration success in tectonically-controlled deep-marine reservoirs relies on a robust understanding of the seismic expression, sedimentology, stratigraphic architecture and trapping styles associated with turbidite systems deposited on bathymetrically-complex slopes. Furthermore, important insights into reservoir size and location can be gained by considering the complete “sediment routing system”.

The emplacement of shallow-level igneous intrusions in sedimentary basins may impact significantly on the development of petroleum systems. For example, the circulation of related hydrothermal fluids, which may reduce the porosity and permeability of host rock reservoirs, and associated host rock deformation may result in the formation of “forced fold” traps. Understanding the geometry and evolution of sub-volcanic intrusive networks in volcanogenic basins is thus of interest to the petroleum industry. Whilst field-based studies permit a detailed investigation of magma properties and localised host rock relationships, outcrops are often too small to fully characterise the three-dimensional geometry and size of large igneous complexes. Furthermore, ancient volcanic edifices, and their relation to the sub-volcanic “plumbing system”, are typically obscured at outcrop due to post-emplacement erosion or caldera collapse. In contrast, seismic reflection data, although typically limited in terms of their vertical resolution, can provide spectacular images of the intrusive and extrusive components of igneous networks.

In this study we use 2D and 3D seismic reflection and borehole data from the offshore Bight Basin (southern Australia) and Exmouth sub-basin (north-western Australia), to illustrate the seismic expression and range of geometries associated with sill-dominated, intrusive igneous networks connected to submarine volcanoes and vents. Three main types of sill are documented: (i) tabular sills; (ii) saucer-shaped sills; and (iii) transgressive sills. Seismic data resolution restricts a detailed analysis of sill volume, but our analysis indicates that the sills are up to 150 m thick, 16 km wide and 208 km2 in map-view area. In both basins, forced folds, which may represent hydrocarbon traps, are developed above a range of sills. In the Bight Basin, the fold amplitudes are consistently less than the thickness of the underlying intrusions. We interpret that this discrepancy reflects fluidisation and ductile flow of coal or carbonaceous claystones during sill emplacement at relatively shallow depths. In both study areas the sill-dominated networks are overlain by large (13 km wide by 800 m high), sub-circular mounds, the majority of which occur above the tips of sills; these mounds are interpreted as extrusive volcanic vents, adjacent to which pinch-out traps, which are related to stratigraphic onlap, may be developed

From an applied perspective, the sill-dominated networks, although areally quite extensive, are not anticipated to impact the vertical migration of hydrocarbons, due to the presence of pervasive normal fault networks that may allow shallow level reservoirs to access deeply-buried source rocks. Although the sills may locally impact the reservoir quality of the host rock successions, forced folding, which is associated with sill emplacement in the shallow sub-surface, can result in the formation of viable hydrocarbon traps.

Our understanding of facies and internal connectivity within carbonate platforms is often inadequate despite the fact that carbonate petroleum systems are wide-spread throughout the world, account for ˜50% of world hydrocarbon reserves and have been heavily studied for many years. Petroleum systems modeling routinely used in exploration allows testing different facies distribution / connectivity scenarios and contributes to a better understanding of key uncertainties and reduction of exploration risk. However, if misused or based on insufficient input data, petroleum systems models may generate misleading results and lead to drilling unnecessary dry holes. This is especially true if the resolution of the model is too low or calibration data is sparse.

Regional-scale petroleum systems models of carbonates often miss the critical details such as platform geometry, facies distribution within a platform and high resolution rock flow/seal properties that are required for a proper evaluation of hydrocarbon migration, prediction of pre-drill pressure and estimation of accumulated hydrocarbons. In addition, they typically don’t address syn- and post-depositional factors such as diagenesis and stress history.

For the purpose of this study, a synthetic carbonate platform was built to demonstrate typical problems associated with modeling carbonate petroleum systems and for testing potential hydrocarbon migration and trapping scenarios. It allows simulating petroleum systems which are similar to the Arab and Khuff formations in the Middle East, isolated platforms in Kazakhstan, and others. This presentation will discuss petroleum systems modeling methodology and guide the audience through different low- vs. high-resolution scenarios leading to dramatically different exploration implications.

Petroleum systems modeling (PSM) is an integration of different geological disciplines to analyze the formation and evolution of sedimentary basins and to study processes such as generation, migration, entrapment and preservation of hydrocarbons. PSM estimates mechanical and chemical compaction of sediments and the resulting porosity/permeability, computes pressure, estimates source rock maturity and the degree of kerogen transformation, models multi-component hydrocarbon generation, expulsion and migration, provides likely locations where hydrocarbons are trapped, and estimates composition and volumes of accumulated hydrocarbons. In addition to its primary function, which is to help reduce exploration risk related to hydrocarbon charge, PSM has become very useful in prediction of pre-drill pressure and effective stress, which are utilized in reservoir and seal quality analysis.

Computational complexity of PSM depends on the quality and resolution of seismic and well input data, maturity of the project (exploration, development or production), availability of tectonic/structural/mechanical earth models, and availability of geochemical data. Typical models at present are not too large (several millions grid cells) and the subsurface is represented by relatively simple structured meshes. The utilization of structured meshes often results in inadequately represented internal model boundaries such as faults and may lead to incorrect hydrocarbon migration scenarios.

The availability of high resolution seismic and well data allows for building higher resolution and more complex models, spanning from seismic to nano, hence allowing for more accurate representation of complex features and processes. This requires incorporation of unstructured/adaptive meshes and also the utilization of algorithms that couple poromechanics, basin modeling, seismic data and inversion, and utilization of high performance computing platforms, e.g., GPU- or FPGA-based as well as optimized libraries for solving large, ill-conditioned, sparse matrices.

This talk presents the state-of-the-art in PSM and discusses recommended directions required for addressing future needs of exploration for conventional / unconventional resources and interactions with geomechanics and seismic.

The MARGINS Source-to Sink paradigm holds that deep-sea sandy successions reflect the evolution of onshore fluvial and adjacent shelf systems, with the potential to record distinct eustatic, climatic, and tectonic signals. Deciphering these signals in modern to Late Cenozoic systems increases our ability to interpret continental margin history preserved in ancient deep marine successions. The practical applications of such studies involve predictions of sand composition in buried deep-sea-fan petroleum reservoirs, which in turn can be directly linked to their likely diagenetic pathway(s) and ultimate reservoir quality.

Recent and ongoing work with my students demonstrates that the modern and ancient passive to active margin sedimentary systems of New Zealand are ideal places for holistic, source-to-sink sand provenance studies. These include the Bounty Fan (BFSS), Canterbury Margin (CMSS), Waipaoa River (WRSS), and the petroliferous Taranaki Basin (TBSS) Sedimentary Systems. Our petrologic data sets include:

1. modern river and beach samples;
2. piston and box core samples;
3. sandy core samples from Ocean Drilling Program and Integrated Ocean Drilling Program sites; and
4. Cenozoic to Mesozoic outcrops within stream drainage basins.

These sand samples include first cycle and multi-cycle detritus derived from similar clastic sedimentary/metasedimentary basement rocks (e.g., Torlesse Terrane), as well as sediments derived from progressively metamorphosed versions of these rocks (e.g., Otago Schist), along with variable volcanic and plutonic input. To date, sand detrital modes have been determined for parts of each system and these demonstrate a variety of processes. Unexpected results include a shut-off of sediment supply linked to onshore tectonism in the BFSS, the dynamic interplay of direct fluvial supply and along-shelf current transport in the CMSS, the importance of coastal erosion in generating shelf sand in the WRSS, and the diversity of potential clastic sediment sources in the TBSS. Provenance models developed using these data will help predict reservoir quality as petroleum exploration expands outward from New Zealand to the largely submerged landmass referred to as “Zealandia.”

Mudrocks comprise any deposit with >50% of grains <62 microns in size. Composition, fabric, and texture often are extremely variable. Major influences on these parameters include tectonic setting, source terrane, basin physiography, water depth, circulation and upwelling, oxygenation, climate, eustasy, and detrital influx. Thus, mudrock character – which ultimately controls the distribution and deliverability of hydrocarbons – is anything BUT homogeneous.

Macroscopic core description, tied to stratigraphic framework and integrated with lab analyses and petrophysical interpretation, is critical in understanding variability and deciphering patterns in composition, fabric, and texture. A rich diversity of facies can be discerned. Sedimentary structures such as ripple cross laminae, graded bedding, scour surfaces, rhythmic couplets, and minute burrows to “cryptobioturbation” are common. Stratigraphic variations in these features relate directly to changing depositional conditions and sequence position.

Mudrocks do not simply fill basins passively. Competition between extrabasinal input and intrabasinal biogenic productivity creates conditions for lithologic cycles, clinoform geometries, and water-column stratification. Benthic fauna colonize the seafloor during dysaerobic to aerobic periods, then experience “terror” during periods of mass transport. An understanding of these stratigraphic relationships requires regional correlations that commonly cover thousands of square miles.

Depositional patterns from basins of the Rocky Mountains, Gulf of Mexico, and Canada suggest that mudrock reservoirs are associated with distinct sequence stratigraphic hierarchies. Most prospective mudrock intervals develop during 2nd-order transgressions. In basins with strong extrabasinal sediment influx, the better reservoirs require load-bearing grains and typically form during either 3rd-order highstands or lowstands. By contrast, in basins dominated by intrabasinal biogenic material the best reservoirs often occur in 3rd-order condensed sections. Such units are frequently brittle, with low clay content, high TOC, and abundant microfossils. Thus, the integration of rock description and sequence framework provides better insight into lateral and vertical changes in mudrock character and reservoir targeting.

Net deposition is accompanied by systematic loss of sediment mass from the transport system. How is this mass loss reflected in the deposits, and to what extent can it be used to predict streamwise facies changes? We review mass-extraction analyses of laboratory experiments on fluvial channel stacking; experimental and field turbidites that show a change from channel-dominated to lobe-dominated deposits at about 80% total mass extraction; and experimental, theoretical, and field studies that show a close connection between rate of mass loss and rate of downstream grain-size fining. Applied thoughtfully, depositional mass balance provides a framework for quantitative prediction and comparison across basins of varying scale and shape.

Physical experiments in laboratory tanks allow observation of basin-scale processes under controlled conditions and greatly accelerated time scales. But to what extent are the observations relevant to the field? Judge for yourself as we review the results of recent experiments on steering of channels by tectonic tilting, interaction of axial and transverse river systems, and wave and tide effects on deltas. We'll also look at natural similarity and its role in explaining the “unreasonable effectiveness” of stratigraphic experiments.

Increasing global demand for energy has forced societies the world over to look for and use ever more diverse and expensive forms of energy to fuel their economies. Oil is a key part of this energy supply, particularly in the arena of transportation fuels. The corporations that supply energy have been pressed into increasingly challenging environments to meet public and governmental demands for inexpensive energy. Unfortunately, as we are reminded by the Gulf of Mexico Deepwater Horizon incident, accidents can happen, the environment can be damaged, and people can lose their lives when we operate at the leading edges of technology.

When accidents occur, our responses typically tend to blame individuals, corporations, or regulators, rather than the public whose demand for cheap, readily available energy forces exploration in new, more challenging frontiers. Public opinions on this subject are shaped by a combination of self-education, fulminating politicians, and aggressive, sensationalist journalists.

Exploring more than societal interests at a national level puts our pursuit of inexpensive energy into context. This context pits the competing interests of developing countries, which demand ever increasing shares of the world's resources, against broader, trans-national interests groups which are worried that continued dependence on energy-dense fossil fuels may cause runaway global warming and climate changes that may in turn destroy the earth's ecosystems.

Ultimate responsibilities for oil spills lie within this mix of competing demands and expectations – a mix far more complicated than most people are aware of or are willing to consider. All of us who consume energy have an ethical obligation to educate ourselves, and those around us, on the consequences of our demands for energy and for the environment.

Hydrothermal dolomites occur in Precambrian to Cenozoic strata with many models for hydrothermal dolomite emphasizing proximity to faults. Although some hydrothermal dolomites occur adjacent to significant faults, many do not. In this presentation, hydrothermal dolomite are described in three intervals and locations – Wabamun Group (upper Devonian) in western Canada, Swan Hills Formation (middle Devonian) in western Canada, and the upper Pennsylvanian at Reinecke Field in west Texas. In all three areas, petrographic and stable isotope data indicate dolomitization at high temperatures after moderate to deep burial.

Porous dolomites are surrounded by impermeable Wabamun limestones creating stratigraphic traps that are scattered across the southern Peace River Arch in western Alberta. Many hydrothermal dolomites in the Wabamun follow depositional facies and early dolomitization. Some oil fields are adjacent to mappable faults, but many are not. Many of the Wabamun fields were discovered by 3D seismic data targeting anomalies away from faults.

Hydrothermal dolomites in and around Rosevear Field in western Alberta occur in grainstones and grain-rich stromatoporoid boundstones. Adjacent micrite-rich facies are generally not dolomitized creating the stratigraphic trap at Rosevear Field. Hydrothermal brines apparently moved up into platform margin grainstones and then moved long distances along the permeable platform margin and connected embayments.

At Reinecke Field in west Texas, hydrothermal dolomites occur in an upper Pennsylvanian limestone buildup. The hydrothermal dolomites created high-permeability horizontal and vertical “raceways” within the largely limestone reservoir. Those “raceways” fundamentally affected oil production during primary, secondary and CO2 recovery at Reinecke Field.

Hydrothermal dolomites are important hydrocarbon reservoirs in many parts of the world. They have excellent reservoir characteristic because of their large crystal sizes, vugs, and fractures. Many factors other than faults can control their distribution including depositional facies, early dolomite, highly saline brines in the basin, and convective flow. Careful petrography, collecting stable isotope data, and a good understanding of the basin history can help predict these types of reservoirs in the subsurface.

The diagenetic evolution of porosity and permeability in carbonates is complex and involves a number of independent factors. Carbonate sediments start with 40-80% porosity and generally lose porosity with time and burial (Schmoker and Halley, 1982), however there are many factors that cause higher and lower porosity in carbonates of the same age and burial depth. Alteration of carbonate sediments during shallow burial is common and includes diagenesis in seawater shortly after deposition, freshwater diagenesis during subaerial exposure, and dolomitization in hypersaline waters. Marine (seawater) diagenesis varies with depth and carbonate saturation as is shown on Enewetak Atoll. Aragonite and Mg-calcite cementation dominate in shallow seawater; however aragonite is dissolved and radiaxial calcite precipitates in moderately deep seawater. In even deeper seawater, calcite dissolves and dolomite precipitates. Freshwater (meteoric) diagenesis and dolomitization commonly rearrange and decrease porosity, but they also impart strength to the rock that reduces porosity loss during deeper burial. Pennsylvanian limestones in west Texas show that prolonged subaerial exposure progressively decreases matrix porosity but increases conduit porosity (fractures and vugs), and hence, formation permeability. Reflux dolomitization is commonly associated with carbonates in arid climates like the Permian of the Permian Basin. The porosity and permeability of reflux dolomites varies according to position in the dolomitizing system with less porosity and permeability in proximal parts of the dolomitizing system. Dolomitization decreases rate of porosity loss with burial (Schmoker and Halley, 1982) allowing some porous dolomite reservoirs like the Smackover of south Alabama at depths of 16,000-18,000 feet. Deep burial dissolution increasing porosity is the exception, rather than the rule. In summary, unlike quartzose sandstones, a complex array of diagenetic factors generally affect the ultimate porosity, permeability and production of carbonate reservoirs.

West Texas and southeast New Mexico contain many classic carbonate exposures with large vertical and lateral extents that allow delineation of major sequence stratigraphic relationships. Sequence stratigraphic relationships help to predict geometries, facies, and early diagenesis in analogous systems in the subsurface. Isolated carbonate buildups are present in Mississippian and Pennsylvanian outcrops in the Sacramento Mountains, and they grew during transgressions when accommodation (relative sea level rise) was greater than or approximately equal to carbonate sediment production. Drowned isolated buildups are commonly excellent carbonate reservoirs throughout the world, including the nearby Horseshoe Atoll.

Ramp carbonates of the Permian San Andres Formation are exposed along the western side of the Guadalupe Mountains. The San Andres has a thick lower transgressive systems tract (TST) overlain by a prograding highstand systems tract (HST). Major hydrocarbon reservoirs occur in similar sequences in the subsurface. Reservoirs are commonly shelf-crest grainstones and adjacent packstones in the upper San Andres HST with structures created by differential compaction over packstone-grainstone buildups in the TST of the lower San Andres.

The Capitan Formation is part of a classic carbonate shelf system dominated by HST progradation. The same system occurs in the subsurface. The structural configuration of the prograding margin is dominated by basinward dip caused by differential compaction associated with the progradation. As a result, the fractured Capitan reef is generally structurally low and wet. Hydrocarbons occur in backreef carbonates and shelfal sands with updip, landward seals formed by impermeable lagoonal evaporites.

3D seismic data show the depositional history of shallow Pleistocene shelf margin, slope and basinal strata in offshore East Kalimantan, Indonesia. Siliciclastic sequences on the shelf are dominated by progradational packages deposited during highstands and falling eustatic sea level. During the last two lowstands of sea level (˜18 and ˜130 ka), coarse siliciclastics were generally not deposited in deep-water environments because lowstand deltas did not prograde over the underlying shelf margin. During the lowstand of sea level that ended at ˜240 ka, deltas prograded over the previous shelf edge, and sand-rich sediments spilled onto the slope.

During the late Pleistocene, siliciclastic sediment supply determined the depositional characteristics of the slope. Channel-levee complexes developed on the slope where deltaic sediment supply was large; in contrast, incised valleys/canyons formed on the slope where siliciclastic input was limited. Pleistocene channel-levee complexes can be traced upslope to lowstand deltas associated with the paleo-Mahakam River. In areas with limited sediment supply, rivers and deltas were generally not present on the outer shelf, including areas upslope from incised slope valleys and canyons. Strata on the basin floor downslope of the slope valleys and canyons are dominated by mass-transport complexes, suggesting that slope valleys and canyons formed by mass failures of the slope, not by erosion associated with turbidite sands derived from rivers or deltas.

In the area with limited sediment supply, one small river was present on the shelf margin during the upper Pleistocene, and sediments originating from its lowstand delta filled a pre-existing slope valley/canyon and formed a basin-floor fan. That slope valley/canyon has a lower fill that consists of amalgamated, sinuous channel deposits and an upper fill consisting of a shale-rich, channel-levee complex. The basin-floor fan also has two parts: a lower fan containing broad lobes with relatively continuous reflectors and an upper fan with a shale-rich, sinuous channel-levee complex that prograded over the lower fan and fed sheet-like lobes on the upper, outer fan. These shallow Pleistocene systems serve as analogs for deeper, more poorly imaged reservoir systems.

The discovery of commercial oil and gas production from shale, or mudstone, reservoirs has dramatically changed how we explore for and develop oil and gas accumulations. In conventional exploration, appraisal and development there is a fairly standard and accepted application of processes and technologies. However, the processes and technologies that are employed in the exploration, appraisal and development of mudstone reservoirs are significantly different, and they are often employed for different reasons and at different stages of the cycle.

Prospect identification is always the initial phase of any exploration project. In most cases in the conventional world this is a result of the interpretation of seismic data, either 2D and/or 3D, in order to identify the areal extent of the prospect, which would typically be on the order of a few hundred acres or in some instances a few thousand acres. However, in the unconventional world the identification is done at a basin level and is not typically supported by seismic, but rather by detailed analysis of a few key wells and their associated petrophysical attributes. Once those attributes are deemed to have the potential of supporting a commercially productive mudstone reservoir, then the utilization of seismic might be employed to help define the boundaries of the reservoir. However, that would typically be the exception as the reservoir boundaries are generally defined by the configuration of the basin, which is generally fairly well understood and can encompass a million acres or more.

Once the prospect has been identified, the evaluation processes during the exploratory drilling phase are dramatically different. During conventional exploration the validation of the presence, or lack, of hydrocarbons is largely done by the acquisition and interpretation of data from open hole wire line logs. While cores, either whole or sidewall, will often be taken, they are typically acquired not to validate the productivity of the reservoir but rather to supplement the open hole log data. In unconventional exploration, the opposite is the case. While the open hole logs are extremely important once the discovery is made to calibrate the reservoir, the most critical data around the validation of the quality of the reservoir is the detailed analysis of the rock acquired from whole core. While some of the attributes that are measured from the mudstone core are common to conventional exploration, there are many more measurements that are taken on mudstone reservoirs that are totally unique to this type of reservoir.

As the prospect moves into appraisal and development mode, there are also unique processes and technologies in the unconventional world that are used to more fully understand the reservoir. The most important of those is the calibration, through the use of specific algorithms, of the data acquired from the whole core data to the open hole data that is being acquired from the appraisal and development drilling. Because the cost and time necessary to acquire an extensive collection of whole core data can be prohibitive, there will be a limited number of wells from which whole core is taken in any given field. Therefore, it is critical to be able to calibrate the various measurements from the whole core to the open hole log data that will be available on many more wells. This is also the point during which 3D seismic would be acquired as opposed to the acquisition of that type of data during the identification process. In unconventional development, the primary benefit of the 3D seismic data is not to identify where you want to drill, but where you don’t want to drill. Specifically, the horizontal lateral is placed to minimize the effect of faulting on the lateral.

Throughout the entire period of field appraisal and development, the practice of geosteering is critical to the economic success of the field. Since virtually all of the unconventional development is done with the application of horizontal drilling, it is critically important that the drill bit maintains its position within the highest quality reservoir while the lateral is being drilled. Since the drilling operations are performed around the clock, and unexpected changes in dip or the presence of faults can cause the bit to rapidly change its relative stratigraphic position, a Gamma Ray tool is incorporated into the bottom hole drilling assembly in order to provide continuous measured depth Gamma Ray log data, which is then converted to a true vertical depth (TVD) log using software designed specifically for this process. This TVD log data is subsequently correlated with nearby well control to determine where the lateral is positioned stratigraphically at all times during the drilling operation. When the bit has been interpreted to be out of the desired stratigraphic section, or target window, it is the responsibility of the geosteerer to collaborate with the drilling organization to make the necessary changes to get the bit back into the target window.