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Tiwari, Arjun (Cairn India Limited) | Harshvardhan, _ (Cairn India Limited) | Mukherjee, Supriya (Cairn India Limited) | Keidel, Steve (Cairn India Limited) | Goodlad, Stephen (Cairn India Limited) | Kumar, Sanjay (Cairn India Limited) | Ghosh, Arnab (Cairn India Limited)
Integration of all subsurface datasets is paramount for building robust reservoir models. These datasets include well, 3D seismic and dynamic data, which taken together form the basis of an integrated reservoir model. Of critical importance in the construction of a reservoir static model is getting the structure right. Towards that goal, we present an example of the Bhagyam field in Rajasthan, India, where horizon based illumination maps have provided both structural and stratigraphic insight where other more conventional attributes, such as time slices or dip /azimuth maps, have fallen short.
The advanced workflows undertaken aided in identifying structural complexity that was not previously captured in early Bhagyam reservoir models. Part of the problem with the early reservoir models was that most of the well data used to build them were drilled above the OWC, owing to the use of screen completions. This resulted in partial penetration of the reservoir. Later, as the completion strategy changed to cased and perforated, wells with full penetration of the reservoir were drilled. These deeper wells provided insight on fault cut outs which was not previously possible. The orientation of faults were interpreted on seismic with the aid of horizon based dip illumination maps, constructed from the seismically most well defined and therefore most confidently interpreted and auto tracked seismic reflections, at or near the reservoir interval. A determination was then made as to whether key faults in the field, with the aid of time varying depletion and water cut data, acted as a conduit or a barrier to fluid flow. The final framework model incorporated all the above datasets in helping to build a robust static as well as simulation model.
A new methodology for basin temperature modelling has been developed that utilizes large volumes (~10,000 points) of properly indexed and QC’d bottom-hole temperature (BHT) data for an onshore basin or area. This methodology honors the observation that borehole temperatures equilibrate, increasing towards formation temperature with elapsed time since fluid circulation. We thus use the maximum BHTs recorded in a layer (normalized for depth) or cell, rather than a corrected average or regression based model.
Two main models have been developed to construct a present day temperature volume (cube): MaxG and MaxBHT. In the MaxG cube, we first define a depth varying interval geothermal gradient (IGG) function that models the maximum envelope of the BHT cloud for each major lithostratigraphic unit. If there is significant erosion in the basin, then the IGG used is adjusted for the maximum burial conditions. The MaxG cube is constructed by stacking the IGG calculated temperatures for all the units in the basin. In the MaxBHT cube, we use the maximum BHT within each cell to populate the cube provided we have sufficiently dense data. If data are lacking in a cell, we can infill the voids using the MaxG cube values or a moving average.
For both the MaxG and MaxBHT cubes, we can apply a temperature shift related to interval thermal conductivity to more closely approximate formation temperature, if appropriate. Both temperature cubes can be used to identify where favorable gas-to-oil ratios (GOR) exist for shale gas formations. The concept is illustrated with examples from the Delaware Basin.
This paper demonstrates where alternate approaches to BHTP analysis and modeling can provide significantly differing potential stimulation treatment geometries, outcomes, and go-forward strategies. We will illustrate this conundrum using cases from the greater Cooper/Eromanga Basin of Central Australia; these cases commonly indicate an interrelationship between production outcomes, the magnitude of in-situ stress and the onset pressure or severity of pressure-dependent leakoff. Historically, treatments can be placed in these environments either after performing numerous diagnostic injections, by increasing pad volumes or by increasing injection fluid viscosity. However, these repeated injections and design alterations may only serve to stabilize the injection environment potentially masking the problem or causing production damage.
We offer recommendations and explore different methods to mitigate these effects in cases where high stress and pressure-dependent behavior are indicated. We demonstrate how strain-corrections are used to correct log-derived rock mechanical properties to history-match initial BHTP responses. The cases presented use either: (1) increases in near-wellbore or near-fracture reservoir pressure; (2) changes in stress due to fracture propagations or horizontal loading; or (3) reductions in pressure-dependent leakoff coefficients to history match subsequent injections over multiple days. Finally, we indicate for each of these complex cases where production results or the desired treatment outcomes may have been altered by repeated diagnostic injections or a job changes.
Although many concepts of Improved Oil Recovery (IOR) were first developed in the Appalachian Basin, early IOR methods were often inefficient and the quantity of oil in place in the various fields was small in comparison to many of the reservoirs found later in other states and countries. For these reasons, a lot of IOR investment money and expertise was not directed to the Appalachian Basin (Basin). This paper generally reviews the IOR methods used and crude oil recoveries in the five oil producing states in the Basin. A discussion is then presented of producing zones and IOR methods that might be successful in the future. Other aspects that could influence IOR development activity such as oil price and domestic demand are also discussed.
While 1998 oil prices do not encourage IOR development in comparatively low recovery oil fields as generally found in the Basin, this paper could serve as a starting point for operators looking for future IOR prospects. This interest could be stimulated by a world oil crisis that demanded an increased development of domestic crude oil production or by higher crude oil prices generated through any number of reasons.
JURASSIC RESERVOIRS OF THE SURAT BASIN Abstract The Surat Basin is a lobe of the Great Artesian Basin, extending over 40,000 square miles in south-eastern Queensland. It is a Jurassic-Cretaceous basin overlying the southern part of the Permian-Triassic Bowen Basin. Sandstone, siltstone, shale and coal with a maximum thickness of 8,000 ft were deposited under mainly shallow continental conditions. A minor marine in- cursion may have occurred during the Lower Jurassic; a major marine transgression occurred in the Lower Cretaceous. About 260 exploratory wells have been drilled. Two commercial oil fields have been found ; recoverable reserves total about 30 million barrels of light, sweet oil. Recoverable reserves of about 100 billion cubic feet (I billion = 1,000 million) of sweet gas have been discovered. The reservoirs are Lower Jurassic sand- stones; the source is believed to have been the asso- ciated Lower Jurassic shale. Résumé Le Bassin de Surat est un sous-bassin du Grand Bassin Artésien couvrant une superficie de 100 O00 kilomètres carrés au Sud Est du Queensland. Le Bassin, d'âge jurassique-crétacé est superposé au Basin de Bowen d'âge permo-triasique. Les sédiments sont con- stitués par des grès, des siltstones, des argiles schisteuses et du charbon (épaisseur maximum de 2500 mètres) et ont été deposés dans des conditions d'eau douce peu profonde. Une incursion, probablement marine, de faible importance s'est produite au Jurassique inférieur ; une transgression marine de grande importance s'est produite au Crétacé inférieur. Deux cent soixante forages d'exploration environ ont été forés. Deux champs de pétrole commerciaux ont été découverts. Des réserves de pétrole sont estimées à 3,8 millions de tonnes. I1 s'agit d'une huile légère, non- sulphurée. Des réserves de gaz sont estimées à 2,9 milliards de mètres cubes. Le gaz n'est pas sulphuré. Les réservoirs de gaz et de pétrole sont tous situés dans les grès du Jurassique inférieur où l'argile schisteuse peut être considerée comme roche-mère.
BASIN SETTING The Surat Basin is a Jurassic-Cretaceous basin ex- tending over 40,000 square miles of south-eastern Queensland. It is the eastern lobe of the Great Artesian Basin, and overlies the southern extension of the Per- mian-Triassic Bowen Basin. Sandstone, siltstone, shale and coal with a maximum thickness of 8,000 feet were deposited under shallow continental conditions. About 260 exploratory wells have been drilled. Re- coverable reserves of about 30 million barrels of light (30" to 54" A.P.I.), sweet oil, and about 100 billion CU ft (1 billion = 1,000 million) of sweet gas, have been found in Jurassic sandstones. This review paper was prepared by D. J. Hogetoorn, under the supervision of R. J. Allen, from published information and data on file in the Geological Survey of Queensland. by D. J. HOGETOORN Geological Survey of Queensland, Australia The Surat Basin overli