In the Midland Basin of west Texas, produced water volumes have historically been disposed into shallow intervals (i.e., Grayburg-San Andres). Over the last decade, the rapid growth in unconventional resource development has resulted in a significant increase in the volume of produced water leading to pressure gradient differences between shallow disposal zones and deeper intervals. These conditions have created drilling challenges and have prompted operators to test additional zones suitable for produced water disposal. In recent years, the Early Ordovician Ellenburger (ELBG) reservoir has become an alternative disposal interval to shallower reservoirs.
The Ellenburger Group of west Texas, a prolific producing reservoir, is part of an extensive carbonate system best known for karst development associated with prolonged subaerial exposure and intervals of high secondary porosity in fracture breccias generated by subsequent cave collapse. Many authors have described fracture occurrence and karst-related breccias of the ELBG, both of which impact productivity at the reservoir scale within the fields and make regional correlations particularly challenging. Ellenburger depositional facies have been described by previous workers in equivalent units across west and central Texas, and textural analysis of high-resolution electrical borehole images from recently drilled disposal wells, combined with core observations, shows corresponding porous intervals to be present in the Midland Basin.
This paper describes the generation of a regional model of porosity distribution within the Ellenburger and assesses the important differences in depositional environment and diagenetic history that exist among the internal units of the ELBG that may impact salt water disposal (SWD) well performance. For example, the Upper ELBG is dominated by fracture porosity in breccia fabrics associated with collapsed cave systems, while the Lower ELBG exhibits preserved porosity associated with original depositional textures. The regional model was tested using multiple datasets: image logs, core descriptions, electric logs from more than 400 well penetrations, and injection data from recent well tests. The integration of these datasets has resulted in a suite of maps of the key stratigraphic intervals within the ELBG that offer the greatest potential for disposal. Additionally, the integration of well performance with observed regional geologic trends was used to identify and tier key performance drivers for deep SWD injection performance, resulting in refined performance maps that can be used for strategic placement of deep SWD wells.
The Cambro-Ordovician succession of Saudi Arabia comprises dominantly siliciclastic sediments deposited in a passive margin intracratonic setting and includes the fluvial to marginal marine Saq Formation (Late Cambrian to early Middle Ordovician), the marine Qasim Formation (late Middle to Late Ordovician) and the glaciogenic Sarah Formation (Hirnantian, latest Ordovician). The Saq Formation is subdivided into the Risha Member (Late Cambrian) and the Sajir Member (Early to Middle Ordovician). Palynological age-control in the Risha Member is provided by a characteristic acritarch assemblage (CB1 Palynozone) which contains well-known Furongian (Late Cambrian) diagnostic taxa (e.g., Trunculumarium revinium, Timofeevia phosphoritica and Ninadiacrodium dumontii), as recorded in one subsurface locality in the Arabian Gulf. This typical assemblage occurs worldwide in Furongianaged strata and not only permits a confident age-attribution, but also indicates an open marine facies within the predominantly fluvial to marginal marine lower Saq Formation. In Oman, the same assemblage occurs in the Al-Bashair Member of the Andam Formation. In the lower part of the Sajir Member, one acritarch assemblage characterized by the presence of Acanthodicaodium angustum and Vulcanisphaera spp., was described from a subsurface section in Eastern Saudi Arabia, indicating an earliest Ordovician (Tremadocian) age. This assemblage forms the O6 Palynozone and suggests correlation with the Mabrouk Member of the Andam Formation in Oman.
The overlay analysis based on real drilling data and our new multidisciplinary results showed that the karst carbonate reservoirs, which could be identified from high seismic amplitudes and validated by real well data, were to some extent controlled by earlier faults, fractures, surface paleogeomorphology and drainage systems, and lithology distribution. As more reservoirs distributed along some earlier faults or fractures, on surface slopes between highs and lows, in areas with active and significant surface water accumulation, and in outcropping area of a certain stratigraphic sub-member of Yingshan formation, etc. However, these geological conditions were not the most dominant controlling factor when considering the study area as a whole. The main controlling factor on karst reservoir development was ascertained at last, based on the integrated analysis considering resultant detailed paleogeomorphology, geological background and the paleoaltitude of karst reservoirs at wells derived from paleogeomorphology. It was concluded that the position of freshwater lens within the carbonate island was the most important controlling factor on reservoir development, which was in turn a combination of paleogeomorphology, sea level and porous host carbonate with weak diagenesis. This meant that the karst reservoirs at different paleoaltitude levels should result from the standstills of rising relative sea-level when the unconformity began to be buried. Besides, it meant that the flank margin caves along the paleo-coasts due to the mixing of fresh water and sea water were the main reservoir type, while the phreatic caves at water tables within the porous carbonate island were secondary reservoir type. And the above was summarized as young carbonate island karstification model (Figure 1).
Copyright 2014, International Petroleum Technology Conference This paper was prepared for presentation at the International Petroleum Technology Conference held in Doha, Qatar, 20-22 January 2014. This paper was selected for presentation by an IPTC Programme Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the International Petroleum Technology Conference and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the International Petroleum Technology Conference, its officers, or members. Papers presented at IPTC are subject to publication review by Sponsor Society Committees of IPTC.
In 1995, Hunt et al drilled the Port au Port #1 discovery well in western Newfoundland, Canada (figure 1). This well successfully tested the Cambro-Ordovician carbonate platform with flow rates of 1520 bbl/d and 1740 bbl/d from thin, porous zones in the upper platform. Four subsequent exploration wells on the Port au Port Peninsula, drilled in the 1990’s, were dry holes. In 2010, Nalcor Energy et al drilled two wells to test a structural trend of this carbonate platform near Parson’s Pond, 200 kilometers north of the Port au Port wells. While some gas was encountered in tight fractures, there were no oil shows and no porosity in the platform units. Though these wells were dry, they have provided new insights into the petroleum system of Anticosti Basin, especially the events that affect porosity development and porosity destruction, source rock richness and hydrocarbon migration.
Post appraisal seismic reprocessing and mapping of the offshore seismic data in 2011-12 and new high resolution aeromagnetic data in 2013 show that older cross faults and late-movement strike-slip faults can now be identified with more confidence. These deep-seated basement faults are thought to be the conduits that introduced late hydrothermal fluids that resulted in the porosity destruction seen at Parson’s Pond. The new data and the well analysis have provide insights that are improving our understanding of the petroleum system of the onshore and offshore areas of the basin.
Through this last decade numerous wells have been drilled to the Ordovician in southern Tunisian Ghadames basin. They have met mudlog gas as well as mudlog oil shows in one or several sandstone levels. Some producing wells from the Silurian section display log pay in the Ordovician but seem to be off to the mapped Ordovician depth structural closure.
Alternatively, large 3D seismic survey has been undertaken in southern Tunisia in order to map the Ordovician. Isochore, isopachs and isobaths maps have been generated on four (04) main reservoir intervals all of which have produced from several fields in the Ghadames Basin (including Algeria and Libya). These reservoirs are (1) Jeffara, (2) Bir Ben Tartar, (3) Kasba Leguine and (4) Sanghar Formations (Tunisian nomenclature). In Southern Tunisia the Upper Jeffara sandstones, the Jeffara sandstones and the Bir Ben Tartar are classified as the primary reservoir intervals.
Generated isochore map of the upper Jeffara sandstones, has been used as evidence of a "geant?? Tunnel valley shape in relationship with other valley structures pertaining to the Libyan side.
As the Ordovician sandstone reservoirs in Tunisia have poor reservoir quality but locally some intervals have tested condensate, some fields have proved that syn-glacial deposits form a gas reservoir (e.g. Tiguentourine field in south-eastern Algeria). Within such facies, the Ordovician has tested gas and/or condensate from a number of wells in the Ghadames basin.
This proposal will involve the existence of valley-fill sandstones pertaining to the Jeffara formation in southern Tunisia giving evidence of sub-glacial environment of deposition where iceproximal glaciofluvial deposits form the highest quality reservoirs using (1) isochore and isopachs maps of the Ordovician, (2) core analyses, (3) cyclostratigraaphy and (4) chemostratigraphy (major and trace elements). This will enhance the exploration activity for the Ordovician in southern Tunisia.
Abu Butabul Field is located within onshore Oman Block 60 in the Western region of the Central Oman Desert (Figure 1). Gas-condensate was discovered in the field in 1998. The main reservoir is the Cambro-Ordovician clastic Barik formation, which is buried over 4200 m below sea level with very low porosity and permeability. Wellbore instability related drilling problems were encountered while drilling most of the appraisal wells in the field. The problems were mainly in the shallower Natih and Nahr Umr formations, Gharif formation and deeper Safiq, Ghudun and Mabrouk formations. A geomechanical modeling study was conducted in the field to understand the causes of the wellbore instability problems and to provide recommendations for drilling new wells.
Data from nine wells were analyzed and used for the construction of 1-D mechanical earth models. Rock mechanical testing data on core samples and pressure and stress memasurement were integrated in the models. Wellbore stability analysis of those wells provided insight into the causes of the wellbore instability problems. To predict wellbore stability at any location in the field more efficiently and capturing the lateral formation property variation as indicated by the seismic data, a 3-D geomechanical model was constructed and subsequently used for predicting wellbore stability for new wells to be drilled in the field and hydraulic fracturing pressures for fracturing stimulation of horizontal wells.
This paper describes the process of constructing the 1-D mechanical earth models, performing wellbore stability analysis for the appraisal wells, , Integeration of 3D seismic Inversion, constructing the 3-D geomechanical model, predicting wellbore stability for new wells using data contained in the 3-D model and post-drill wellbore stability analysis of the planned wells.
Pool, Wilfred (NAM) | Geluk, Mark (Shell Int. E&P) | Abels, Janneke (Shell International E&P) | Tiley, Graham John (Shell International E&P) | Idiz, Erdem (Shell Global Solutions International) | Leenaarts, Elise
In 2008 Shell obtained two licenses for unconventional gas exploration in the Skåne region of southern Sweden, with a total size of 2500 km2 (600,000 ac). The objective was the Cambro-Ordovician Alum Shale, one of the thickest and richest marine source rocks in onshore northern Europe.
The licenses covered the Höllviken Graben and the Colonus Shale Trough. In both areas the Alum Shale had been encountered in older wells, with a thickness of up to 90 m and TOC values up to 15%. Maturities of up to 2% Vre were considered encouraging for a shale gas play. Relative high quartz contents suggested good fraccability of the shales. All data was obtained through public sources. Identified risks were the uncertain timing of hydrocarbon generation and the position of the licenses adjacent to the Trans-European Suture Zone where several phases of fault movement have a risk for actually retaining the hydrocarbons.
The derisking strategy for this opportunity was based on both technical and non-technical aspects. Aim was to collect geological and geophysical data to constrain depth and thickness of the shale and to identify potential dolerite dykes. In addition, well data were needed to establish rock properties and gas content. The external environment, especially concerns from the people in Skåne regarding the visual impact of activities and potential impact of drilling activities on the aquifers and on the tourism industry have resulted in extensive engagements with stakeholders and specific requirements around seismic acquisition (low impact), site preparation and operations (e.g. small rig, different lighting).
80 km of 2D seismic was acquired in 2008 and three wells, with a final depth of around 1000 m, were drilled in 2009 to mid 2010. The Alum shale was fully cored and the well sites have been restored. Thickness, richness and maturity of the Alum were as predicted although the basin was shallower than previously anticipated. Canister desorption tests, however, indicated that the shales have only low gas saturation. This significantly increased the risk for a viable shale gas play and therefore the licenses were not renewed after the initial 3 year period.
Lemiszki, P.J. (Department of Geological Sciences, University of Tennessee, Knoxville, & Environmental Sciences Division, Oak Ridge National Laboratory) | Landes, J.D. (Department of Mechanical & Aerospace Engineering and Engineering Science, University of Tennessee)