Numerous integrative approaches can be taken to link subsurface rock-type characterization to related openhole wireline log attributes. In this study, focus and emphasis was geared towards developing rock-typing models that link depositional environments to petrophysical property space trends and variations to then guide subsurface modeling. Multiple technical paths were taken, and tools used to link observed rock types in full-diameter conventional cores and related measured geological attributes to electrofacies and the refined petrofacies characterization. The data integration used a significant volume of core analytical and openhole wireline log suites including a base suite of triple-combo data (gamma ray, neutron, density, and resistivity) and expanding to include resistivity borehole image data. We present how the addition of various subsurface datasets impacts rock-typing efforts and accuracy. A cluster-based, least-mean-squares analytical result is observed and discussed in an unsupervised model application and is compared to a supervised model application. The relative importance of various attributes is discussed and used to recommend a workflow for Permian-focused rock typing that allows the subsurface characterization to be extrapolated to regional (basinwide) and local (single-well) scales. In short, we focus on sharing a workflow to effectively link core description (sedimentologic observations) and raw log analytics to refine and upscale rock property distributions for use in sequence stratigraphic frameworks, regional basin depositional models and multiscale modeling efforts.
The combination of extended-length horizontal drilling and high volume hydraulic fracturing has led to previously unimaginable production increases, yet the recovery potential of unconventional oil and gas resources remains largely unrealized. Recovery factors for unconventional oil and gas wells are typically reported at < 20% in gas shale reservoirs and < 10% in the oil plays.
Neutrally buoyant ultra-lightweight proppants have been demonstrated to effectively provide production from fracture area that is otherwise unpropped and thus, non-contributive with conventional sand/slickwater hydraulic fracturing processes. Production simulations illustrate that treatment designs incorporating neutrally buoyant ULW proppant treatment designs tailored for contemporary unconventional well stimulations deliver cumulative production increases of 30% to over 50% compared to the typical large volume sand/slickwater treatments. Unfortunately, production simulation results may not sufficiently lessen risk uncertainties for operators planning high-cost multi-stage horizontal stimulations. Therefore, several field trial projects using the neutrally buoyant ULW proppant in extended-length horizontal unconventional wells are currently in progress to validate the production simulations.
Since the initial 4-stage fracturing stimulation incorporating neutrally buoyant ultra-lightweight proppant in 2007, deployment has occurred in fracture stimulating hundreds of oil and gas wells spanning multiple basins and reservoirs. Most of the wells are vertical or relatively short lateral wells common to asset development practices predating the unconventional shale completions mania, but many were targeted at the same unconventional reservoirs as the current multi-stage horizontal completions. Several published case histories have documented the production enhancement benefits afforded by the legacy ULW proppant wells, but questions remained as to how those lessons might be correlated to provide engineers confidence in the current production simulations.
Well completion and production information was mined from the various accessible databases for the neutrally buoyant ULW proppant wells. The scope of the legacy data compiled for analysis was limited to the reservoirs common to the current field trials and production simulations, ie. unconventional oil and gas shale reservoirs. Production performance contributions of neutrally buoyant ULW proppant in past applications were compared with the production uplift observed in applications and/or simulated application of neutrally buoyant ultra-lightweight proppant fracturing treatments in current multi-stage horizontal reservoirs.
The lessons learned from this investigation provide the practicing engineer the means to confidently assess production simulation data for multi-stage horizontal unconventional completions incorporating neutrally buoyant ulw proppant in the treatment designs.
Africa (Sub-Sahara) United Hydrocarbon International finished drilling the Belanga North-1 exploration well located in Doba basin in southern Chad. The well was drilled to a total depth of 1392 m, and encountered three oil-bearing sand intervals--two in the targeted Upper Cretaceous "YO" sands and one in an untested shallower sand. United Hydrocarbon (100%) is the operator. Asia Pacific China National Offshore Oil Corporation discovered natural gas in the Qiongdongan basin, South China Sea. Well Lingshui 17-2--located in the east Lingshui sag portion of the basin at an average water depth of 1450 m--was drilled and completed to a depth of 3510 m. Lingshui 17-2 encountered a gas reservoir with a total thickness of approximately 55 m. Statoil Australia Theta has drilled and completed the Oz-Alpha 1 exploration well in the southern Georgina basin in the Northern Territory, Australia.
An oil and natural gas producer should continuously analyze industry fundamentals such as supply, demand, storage, transportation, and pricing to make informed operational and business decisions. An oil and gas producer should be able to adapt to frequently changing industry environment by adjusting its operation: increasing or curtailing production, drilling and connecting new wells, obtaining new financing, locking in future natural gas prices, etc. In order to provide an input to the decision-making process, the adaptive management methodology needs to be applied.
Forecasts of hydrocarbon resources, production, infrastructure, and pricing are very sensitive to technological improvements, pricing changes, new discoveries, and other major events, the impacts of which are difficult to predict. One method to improve the quality of a forecast is to apply adaptive management process. The adaptive management methodology implies assuming supply and demand strategy, creating multiple scenarios for allocating oil or gas demand to different areas or regions, evaluating these scenarios, and performing detailed forecast for selected scenarios. One important step of adaptive management is monitoring of actual drilling and production activities. Based on this information original assumptions can be updated.
The result of the analysis is production, prices, and infrastructure forecast. The paper presents an example of a production forecast that is generated using adaptive management process.
Raney, Kirk (Locus Bio-Energy Solutions, LLC) | Alibek, Ken (Locus Bio-Energy Solutions, LLC) | Shumway, Martin (Locus Bio-Energy Solutions, LLC) | Karathur, Karthik (Locus Bio-Energy Solutions, LLC) | Stanislav, Terry (Locus Bio-Energy Solutions, LLC) | West, Gary (Locus Bio-Energy Solutions, LLC) | Jacobs, Marc (Penneco Oil Company)
New biochemically-derived products for the removal of paraffin wax from oil wells do not require additional capex nor heat and do not utilize bacteria. They contain inactivated microbial cells, biosurfactants and biosolvents, and other components harvested as microbial byproducts that emulsify and dissolve paraffin from rock pores and from the well surfaces over wide temperature, salinity, depth, and pH ranges. Additionally, they increase oil recovery by remediating near-wellbore formation damage, reducing interfacial tension, altering rock surfaces and changing their wettability, and reducing oil viscosity. The product application is environmentally superior to well treatments using hot oil/water and aromatic solvents and is economical due to low capital and operating costs required for product synthesis. Specifically, product preparation is achieved using a modular fermentation system that is installed near the points of application. This insures highly efficient and low-cost production and logistics, as well as reducing time from generation to application which maximizes potency. With sufficient space, water, and electricity, the initial manufacture of the dispersal products can occur within a few weeks.
The treatment products utilized were initially developed and tested in laboratory studies, which showed that dispersion rates of the relevant paraffin samples were comparable to those achieved with toluene. The paraffin dispersal products exhibit a very high level of efficacy and safety when deployed in the Appalachian and Permian Basins. The potency of these products has led to outstanding paraffin removal results as indicated by reduced well failures in both vertical and horizontal wells and by visual observation of sucker rods removed from the wells. In addition, tank sludge and wax deposits in pipelines can be removed through either residual product flowing from the well or through direct application. Growth of detrimental bacteria and formation of biofilms are inhibited by the product application thereby reducing corrosion risk.
Specifically, details of an almost two-year 70-well study in the Appalachian Basin are reported in which no well failures were observed due to paraffin buildup and 95% of the wells exhibited an enhanced oil recovery effect during the paraffin remediation treatments. This resulted in an approximate 50% average increase in sustained production rate over baseline. Analysis of the results forecasts a substantial increase in future production, thereby significantly enhancing the value of the producing wells. Importantly, longer times between required treatments and the increased recovery rates have transformed the paraffin maintenance program into a documented revenue generator for the operator.
Differential compaction is an inherent process in carbonate systems that is thought to produce early natural fractures prior to any significant burial. Such fractures can persist and can be major permeability pathways, including areas of minor tectonic overprint. We forward model differential compaction fracturing in a carbonate reservoir in effort to predict the location of fractures in the subsurface.
3D finite-element geomechanical models are created to simulate differential compaction fracturing at a carbonate platform scale (kilometers) and the smaller carbonate build-up scale (10s of meters) commonly present within carbonate platforms. Interpreted seismic surfaces of key reservoir horizons are used as an input for the platform-scale model. Geometry of carbonate build-up from an outcrop analog is used for the build-up scale models. In both type of models layers identified to be compaction prone are restored to their expected pre-compaction state. A simplified mechanical stratigraphy scheme is adopted to distribute mechanical properties within the models consistent with their expected pre-burial properties.
Geomechanical modeling in this study was applied to a field which includes two carbonate platforms at different stratigraphic levels. Modeling results predict increased fracture intensity at the windward margin of the carbonate platform. This coincides with increased windward-leeward asymmetry of an underlying older platform. Increased fracture intensity is predicted at the center of the platform where the underlying older platform displays significantly less asymmetry. Predicted fracture locations over the platform top also correspond with the location of carbonate build-ups identified from seismic data. Fracture observations from image logs and indirectly from mud loss data within the upper platform are consistent with our modeling results. Predicted areas of greatest fracture intensity correspond with the location of wells with the highest fracture intensity observed from image logs.
Build-up scale models suggest that the build-up shape exerts a major control on the resulting differential compaction fracture pattern. Elongate build-ups tend to produce fractures oriented parallel to their axes. Circular build-ups tends to produce radial fracture patterns. Fracture orientation from image logs along with build-up shape observed using the coherence seismic attribute are consistent with these findings.
This study offers a process-based fracture modeling approach that can enhance the predictability of the location and orientations of natural fractures in carbonate reservoirs.
Pipelines and roads represent the arteries of the oil and gas, and mining and transportation industries, respectively. They move product from remote locations to more centralized locations, either for processing or for shipping to refineries and mills for subsequent processing. Proper infrastructure development is critical to the successful development of the sensitive Arctic environment especially true in light of ongoing climate change where the melting of permafrost poses significant issues for development in the Arctic. The harsh Arctic environment presents unique challenges that are not found in more southern latitudes for the oil and gas and transportation sectors, including permafrost and permafrost degradation. It is well acknowledged that the extent of permafrost in northern environments is poorly known and mapped.
New tools are being used to help determine the extent of permafrost and to identify areas that are more susceptible to permafrost degradation in light of on-going and future development. One such tool is the use of softcopy mapping to help map terrain and geological modifying processes such as permafrost. Softcopy uses traditional stereo aerial photographs in a digital environment to allow scientists the ability to view the landscape at scales of 1:1,000 from traditional aerial photography that were captured at scales of 1:24,000 to 1:40,000. The advantage of softcopy is that by being able to zoom down to such large scales allows terrain scientists the ability to better determine the soil types (sand, silt or clay), drainage conditions (rapid to very poor) and on-going geological processes such as permafrost as evidenced by frost boils and permafrost degradation as evidenced by presence of thermokarst and thaw slides. Another method often utilized where stereo aerial photography is not available is use of remote sensing datasets such high resolution digital elevation models and satellite imagery which are becoming general available in Arctic regions. These elevation models are used to create hillshade images of varying aspects and photorealistic 3D models to help map terrains.
This paper will present a number of examples of where such mapping has been used to assist in pipeline and infrastructure planning in Alaska and Canada's north.
Lin, Yani (Missouri University of Science and Technology) | Zhang, Tianze (Missouri University of Science and Technology) | Liu, Kelly H. (Missouri University of Science and Technology) | Gao, Stephen S. (Missouri University of Science and Technology)
Sand-rich deposits in the submarine canyon system in the central Gulf Coast region of Texas are considered as high exploration potential reservoir bodies. However, the multi-phase regression and transgression during the early Eocene complicate the structure position and the sand body distribution. Seismic attributes have been proven to be sensitive to seismic amplitude for detecting channels and canyons for decades. Specifically, the variance attribute is useful in distinguishing stratigraphic features, the root-mean-square (RMS) amplitude attribute is a good indicator of amplitude anomalies, and spectral decomposition is specialized in revealing the variations of layer thickness. In this study, we combine the variance and RMS amplitude attributes to detect the edges of the canyon and perform spectral decomposition to analyze the varying thickness of the sand bodies. Identification of the canyon system can provide significant constraint on predicting the distribution of the reservoir sand, and consequently improve the evaluation of production potential.
Presentation Date: Monday, October 15, 2018
Start Time: 1:50:00 PM
Location: Poster Station 1
Presentation Type: Poster
The paper reviews the advantages of exploiting the deepwater phenomena of the early and progressive growth of the fracture gradient immediately below the mudline in determining casing seat setting depths. This would improve the reliability, well integrity and economics of deepwater wells. This method allows the subsea structural casing string, the first string in any deepwater well design, to have a dual purpose of supporting the required subsea axial loads while providing sufficient shoe strength for the subsequent casing string. This allows subsequent casing seats to be set deeper than current practice reducing the number of casing strings to attain well programmed depths.
The conventional deepwater well design uses the criteria of the structural casing primarily to support the anticipated axial load of the subsequent string(s) for its setting depth. The practice is to jet the structural casing to depths of 200 to 300 ft below seafloor. This results in insufficient leak-off shoe strength to adequately mitigate any shallow hazards that may exist such as shallow gas, near-surface active faulting, shallow water flows and gas hydrates. Therefore, a casing string is generally set just above every identified hazard, adding rig time and increasing the number of casing strings in the well design. This can be detrimental to the well objectives by creating high equivalent circulating densities (ECD) in the lower well sections. These ECD's in narrow drilling windows can prevent continued drilling, or at a minimum cause significant lost time. This situation is a typical problem in the deepwater drilling environment.
The deepwater drilling industry has had to recognize the shortcomings in existing well designs. Many of the principles and practices used in deepwater have been adopted and adapted from shallow water experience with various level of success. Leading GOM drilling professionals have noted that deepwater well designs and execution practices need to be challenged, especially in light of the BP Macondo incident, to drive for improved well integrity, and of course economics.
The proposed deepwater well design method could replace the practice of "jetting" in the structural casing with drilling-in the casing to about 1500 ft below seafloor. This could be done without any modification to existing wellhead designs. The result would be: Increased well integrity: In the riserless section, mitigating shallow hazards with stronger casing shoes. Ensures structural casing is placed at optimum depth to provide maximum bending moment resistance. Below HPWH conductor, increase the drilling operating windows (larger annuli). Decreased well cost: Reduce at least one casing string. Minimize trouble time with narrow drilling windows and "junked" wells. Increased well objective reliability: Less casings and larger holes below the HPWH and its conductor allow additional casing strings for geological or mechanical sidetracks. Increases drilling operating window to reach programmed TD.
Increased well integrity:
In the riserless section, mitigating shallow hazards with stronger casing shoes.
Ensures structural casing is placed at optimum depth to provide maximum bending moment resistance.
Below HPWH conductor, increase the drilling operating windows (larger annuli).
Decreased well cost:
Reduce at least one casing string.
Minimize trouble time with narrow drilling windows and "junked" wells.
Increased well objective reliability:
Less casings and larger holes below the HPWH and its conductor allow additional casing strings for geological or mechanical sidetracks.
Increases drilling operating window to reach programmed TD.
The concerns surrounding the well integrity of deepwater wells with both the existing well design and the need for deepwater projects to reduce their costs to compete for investment funding has become the force for change.
Moffitt, K. (Golder Associates Inc.) | Yetisir, M. (Golder Associates Inc.) | Sherizadeh, T. (Golder Associates Inc.) | Carvalho, J. L. (Golder Associates Ltd) | Cambio, D. (Rio Tinto Kennecott) | Hicks, D. (Rio Tinto Kennecott) | Gaida, M. (Rio Tinto Kennecott) | Jung, J. (Rio Tinto Kennecott)
A 610 m (2000 foot) high portion of the South Wall of the Bingham Canyon open pit has experienced slow-moving slope deformations several times during spring melt until the movement was stabilized approximately 7 years ago. To develop and optimize life of mine (LOM) slope designs, an understanding of the mechanism(s) and associated material strength parameters, was required. A back-analysis and calibration of the strength parameters for the salient rock mass and structural features was undertaken. The back-analysis consisted of understanding the conditions and trigger for the slope movement and adjusting strength parameters to match available monitoring data (TDR cables, inclinometers, IBIS radar data, etc.). The trigger for the movement was attributed to the spring high-perched water levels in the upper part of the wall. The back-analyses was consistent with the conceptual model and indicated that the slide was composed of mixed mechanisms, namely, a structurally controlled mechanism for the upper wall and a rock mass controlled mechanism for the lower wall (toe). Today, the O-Slide instability has been fully managed by rigorous monitoring, implementation of a toe buttress, successful dewatering efforts, and unloading of the movement mass as another slice of mining advanced down the South Wall.
Back- analysis of a large-scale pit slope movement (O-Slide movement) at Bingham Canyon Mine was undertaken to confirm the mechanism of movement and calibrate relevant material properties. The back analyses was undertaken in 3D using FLAC3D (Itasca) The O-Slide is an area that experienced multiple periods of accelerated slope movement between 2002 and 2011. Visual observations and monitoring data showed the progression of the movement. The deformation monitoring prisms indicated an increasing trend during the spring of 2003, 2004, and 2006. The extent and pattern of deformation were also well defined by IBIS radar. In the spring and summer of 2011 deformation rates accelerated, reaching up to 3.6 m (12 ft.) of deformation.
This paper presents a summary of the construction of the South Wall 3D numerical model, back-analysis of the 2011 O-Slide period, the monitoring data utilized for comparison against the back-analysis model predictions, and the learnings from this back-analysis to be applied in future modeling efforts for the mine.