A REVISED DEPOSITIONAL MODEL FOR EAST SPAR AND ITS IMPACT ON FIELD PERFORMANCE

2002 ◽  
Vol 42 (1) ◽  
pp. 461 ◽  
Author(s):  
N.P. Tupper ◽  
E.F. Tadiar ◽  
D.L. Price ◽  
J.D.S. Goodall
Keyword(s):  
Bottom Water ◽  
Field Performance ◽  
Depositional Model ◽  
Incised Valley ◽  
Water Influx ◽  
Lateral Extent ◽  
Well Data ◽  
Multi Phase ◽  
Regional Aquifer ◽  
Carnarvon Basin

The East Spar gas condensate field is located in production licence WA-13-L in the offshore Carnarvon Basin. Production commenced in 1996 with two subsea wells linked to processing facilities on Varanus Island via a multi-phase pipeline. The pressure performance of the field has been significantly different to predevelopment expectations. This prompted a reexamination of the seismic and well data to investigate the potential for alternative reservoir models.Integrated stratigraphic and seismic interpretation reveals that the Barrow Group reservoir sands were deposited within an incised valley of limited lateral extent. Sea level fall instigated erosion of a valley that on transgression was filled with successive fluvial, estuarine and marine sediments. Good quality sands are expected to be limited to this valley, the upper part of which can be mapped on seismic. Poor sand development in East Spar–2ST is consistent with its location at the edge of the incised valley.Before development, the primary production mechanism was expected to be a strong bottom water drive comparable with other Barrow Group fields in the Carnarvon Basin. The revised depositional model, however, and the observed decline in reservoir pressure, indicate that connection to this regional aquifer is limited. This implies that water influx will probably be later, and ultimate recovery higher, than previously anticipated.

A Mathematical Model Water Movement about Bottom-Water-Drive Reservoirs

1962 ◽  
Vol 2 (01) ◽  
pp. 44-52 ◽  
Author(s):  
Keith H. Coats
Keyword(s):  
Pore Volume ◽  
Bottom Water ◽  
Flow Model ◽  
Radial Flow ◽  
Water Movement ◽  
Gas Storage ◽  
Reservoir Pressure ◽  
Influx Rate ◽  
Aquifer System ◽  
Water Influx

Abstract This paper presents the development and solution of a mathematical model for aquifer water movement about bottom-water-drive reservoirs. Pressure gradients in the vertical direction due to water flow are taken into account. A vertical permeability equal to a fraction of the horizontal permeability is also included in the model. The solution is given in the form of a dimensionless pressure-drop quantity tabulated as a function of dimensionless time. This quantity can be used in given equations to compute reservoir pressure from a known water-influx rate, to predict water- in flux rate (or cumulative amount) from a reservoir- pressure schedule or to predict gas reservoir pressure and pore-volume performance from a given gas-in-place schedule. The model is applied in example problems to gas-storage reservoirs, and the difference between reservoir performances predicted by the thick sand model of this paper and the horizontal, radial-flow model is shown to be appreciable. Introduction The calculation of aquifer water movement into or out of oil and gas reservoirs situated on aquifers is important in pressure maintenance studies, material-balance and well-flooding calculations. In gas storage operations, a knowledge of the water movement is especially important in predicting pressure and pore-volume behavior. Throughout this paper the term "pore volume" denotes volume occupied by the reservoir fluid, while the term "flow model" refers to the idealized or mathematical representation of water flow in the reservoir-aquifer system. The prediction of water movement requires selection of a flow model for the reservoir-aquifer system. A physically reasonable flow model treated in detail to date is the radial-flow model considered by van Everdingen and Hurst. In many cases the reservoir is situated on top of the aquifer with a continuous horizontal interface between reservoir fluid and aquifer water and with a significant depth of aquifer underlying the reservoir. In these cases, bottom-water drive will occur, and a three-dimensional model accounting for the pressure gradient and water flow in the vertical direction should be employed. This paper treats such a model in detail--from the description of the model through formulation of the governing partial differential equation to solution of the equation and preparation of tables giving dimensionless pressure drop as a function of dimensionless time. The model rigorously accounts for the practical case of a vertical permeability equal to some fraction of the horizontal permeability. The pressure-drop values can be used in given equations to predict reservoir pressure from a known water-influx rate or to predict water-influx rate (or cumulative amount) when the reservoir pressure is known. The inclusion of gravity in this analysis is actually trivial since gravity has virtually no effect on the flow of a homogeneous, slightly compressible fluid in a fixed-boundary system subject to the boundary conditions imposed in this study. Thus, if the acceleration of gravity is set equal to zero in the following equations, the final result is unchanged. The pressure distribution is altered by inclusion of gravity in the analysis, but only by the time-constant hydrostatic head. The equations developed are applied in an example case study to predict the pressure and pore-volume behavior of a gas storage reservoir. The prediction of reservoir performance based on the bottom-water-drive model is shown to differ significantly from that based on van Everdingen and Hurst's horizontal-flow model. DESCRIPTION OF FLOW MODEL The edge-water-drive flow model treated by van Everdingen and Hurst is shown in Fig. 1a. The aquifer thickness is small in relation to reservoir radius water invades or recedes from the field at the latter's edges, and only horizontal radial flow is considered as shown in Fig. 1b. The bottom-water-drive reservoir-aquifer system treated herein is sketched in Fig. 2a and 2b. SPEJ P. 44^

Geothermal potential of the Tubbergen Formation in the Twente region of east Netherlands

2020 ◽  
Vol 8 (4) ◽  
pp. SQ93-SQ103 ◽  
Author(s):  
Edo Veenstra ◽  
Paul de Groot ◽  
John de Lange ◽  
Andre Mol ◽  
Piet van den Heuvel
Keyword(s):  
Lower Cost ◽  
Block Size ◽  
Economic Feasibility ◽  
Reservoir Simulations ◽  
Prevailing Paradigm ◽  
Geothermal Potential ◽  
Porosity And Permeability ◽  
Lateral Extent ◽  
Well Data ◽  
The City

We have determined the potential geothermal prospectivity of clean sandstones in the Tubbergen Formation (Late Carboniferous) of the Twente area (eastern Netherlands). We were motivated by the prevailing paradigm that in the Netherlands geothermal power can only be harvested economically through large, expensive installations producing high volumes from high-quality aquifers located between approximately 1500 and 2500 m. No such aquifers are present in Twente. We found that heat production is economically feasible from the Tubbergen Formation sandstones by producing smaller volumes from smaller, highly efficient installations that can be developed at considerably lower cost. Our reinterpretation of publicly available seismic and well data shows that potentially suitable sandstones occur over the whole area with thicknesses of up to 50 m, porosities reaching 20%, and permeabilities reaching 300 mD. The Tubbergen Formation is approximately 400–700 m thick in the study area and contains approximately 60% sandstone. The top reservoir reaches an approximate 1500 m depth in the southwest, and the base reaches some 4300 m in the northeast of the study area. The temperature is expected to range between 60°C and 140°C depending on the depth. The Carboniferous is densely faulted with a block size of approximately 3 × 4 km, each block being a potential target for geothermal development. To determine the economic feasibility, we performed an economic screening for a hypothetical location north of the city of Enschede and backed this up by reservoir simulations. The geologic risks of the Tubbergen Formation are the lack of permeability, reservoir thickness, and lateral extent of the reservoirs. In our judgment, the chance of economic success for this site is 50% or more. Upside potential is present in numerous fault blocks in the study area and in adjacent areas where suitable sandstones with similar porosity and permeability at greater depth and higher temperatures are expected.

scholarly journals Artificial neural network models for reservoir-aquifer dimensionless variables: influx and pressure prediction for water influx calculation

2021 ◽  
Vol 11 (4) ◽  
pp. 1885-1904
Author(s):  
Anietie Ndarake Okon ◽  
Idongesit Bassey Ansa
Keyword(s):  
Neural Network ◽  
Artificial Neural Network ◽  
Mean Square Error ◽  
Bottom Water ◽  
Mean Square ◽  
Petroleum Reservoir ◽  
Statistical Measures ◽  
Water Influx ◽  
Ann Models ◽  
Artificial Neural

AbstractCalculation of water influx into petroleum reservoir is a tedious evaluation with significant reservoir engineering applications. The classical approach developed by van Everdingen–Hurst (vEH) based on diffusivity equation solution had been the fulcrum for water influx calculation in both finite and infinite-acting aquifers. The vEH model for edge-water drive reservoirs was modified by Allard and Chen for bottom-water drive reservoirs. Regrettably, these models solution variables: dimensionless influx ($$W_{{{\text{eD}}}}$$ W eD ) and dimensionless pressure ($$P_{D}$$ P D ) were presented in tabular form. In most cases, table look-up and interpolation between time entries are necessary to determine these variables, which makes the vEH approach tedious for water influx estimation. In this study, artificial neural network (ANN) models to predict the reservoir-aquifer variables $$W_{{{\text{eD}}}}$$ W eD and $$P_{D}$$ P D was developed based on the vEH datasets for the edge- and bottom-water finite and infinite-acting aquifers. The overall performance of the developed ANN models correlation coefficients (R) was 0.99983 and 0.99978 for the edge- and bottom-water finite aquifer, while edge- and bottom-water infinite-acting aquifer was 0.99992 and 0.99997, respectively. With new datasets, the generalization capacities of the developed models were evaluated using statistical tools: coefficient of determination (R2), R, mean square error (MSE), root-mean-square error (RMSE) and absolute average relative error (AARE). Comparing the developed finite aquifer models predicted $$W_{{{\text{eD}}}}$$ W eD with Lagrangian interpolation approach resulted in R2, R, MSE, RMSE and AARE of 0.9984, 0.9992, 0.3496, 0.5913 and 0.2414 for edge-water drive and 0.9993, 0.9996, 0.1863, 0.4316 and 0.2215 for bottom-water drive. Also, infinite-acting aquifer models (Model-1) resulted in R2, R, MSE, RMSE and AARE of 0.9999, 0.9999, 0.5447, 0.7380 and 0.2329 for edge-water drive, while bottom-water drive had 0.9999, 0.9999, 0.2299, 0.4795 and 0.1282. Again, the edge-water infinite-acting model predicted $$W_{{{\text{eD}}}}$$ W eD and Edwardson et al. polynomial estimated $$W_{eD}$$ W eD resulted in the R2 value of 0.9996, R of 0.9998, MSE of 4.740 × 10–4, RMSE of 0.0218 and AARE of 0.0147. Furthermore, the developed ANN models generalization performance was compared with some models for estimating $$P_{D}$$ P D . The results obtained for finite aquifer model showed the statistical measures: R2, R, MSE, RMSE and AARE of 0.9985, 0.9993, 0.0125, 0.1117 and 0.0678 with Chatas model and 0.9863, 0.9931, 0.1411, 0.3756 and 0.2310 with Fanchi equation. The infinite-acting aquifer model had 0.9999, 0.9999, 0.1750, 0.0133 and 7.333 × 10–3 with Edwardson et al. polynomial, then 0.9865, 09,933, 0.0143, 0.1194 and 0.0831 with Lee model and 0.9991, 0.9996, 1.079 × 10–3, 0.0328 and 0.0282 with Fanchi model. Therefore, the developed ANN models can predict $$W_{{{\text{eD}}}}$$ W eD and $$P_{D}$$ P D for the various aquifer sizes provided by vEH datasets for water influx calculation.

The Experimental Research of the Restricting Factors of Water Invasion of Yulou Reservoir in Jin 45 Block

2013 ◽  
Vol 838-841 ◽  
pp. 1655-1658
Author(s):  
Shi Min Zhang
Keyword(s):  
Bottom Water ◽  
Permeability Transition ◽  
Differential Pressure ◽  
High Permeability ◽  
Development Mode ◽  
Index Function ◽  
Steam Flooding ◽  
Water Influx ◽  
Technical Risks ◽  
Water Rate

Jin 45 block has entered the later period of cyclic steam, Transforming the development mode is imminent,there is a big technical risks in the development of cyclic steam of edge and bottom water of heavy oil when it turns to steam flooding development, it is needed to understand the characteristics of Edge-bottom water which invades in reservoir and master the restricting factors of invasion of the edge-bottom water,to avoid the risk of steam flooding development reasonably and effectively. The experiment uses the three layers of inhomogeneous Artificial core which has high permeability transition zone of simulative edge water on the edge. Analysis the factors of differential pressure, temperature and distance of the water and bottom water to the effect of Edge-bottom water encroachment sensitivity. The results show that: Among many factors of water encroachment sensitivity, the effect of differential pressure to the regularity of water invasion is most obvious, at the stage of Connection of water invasion, the differential pressure has a little effect on the Instantaneous water influx, After the channel of water encroachment has formed,Instantaneous water rate and differential pressure is index function relation, in the late of water invasion, the instantaneous water rate is stable. The result provides the basis for the heavy waterflooded area turn to steam flooding.

An Integrated Reservoir Predicting Approach with Geological Constraints from Stratigraphic Forward Modeling of the Miocene Fan Delta in Albert Basin, Uganda

2021 ◽  
Author(s):  
Wei Xu ◽  
Lei Fang ◽  
Jingyun Zou ◽  
Fuxin Guo ◽  
Yingchun Zhang ◽  
...  
Keyword(s):  
Deposition Process ◽  
Sediment Supply ◽  
Heavy Minerals ◽  
Depositional Model ◽  
Sedimentary Process ◽  
Reservoir Prediction ◽  
Fan Delta ◽  
Well Pattern ◽  
Well Data ◽  
Exploration And Development

Abstract Reservoir prediction is a core area of research in oilfield exploration and development, and it is generally constructed on a combination of well data, seismic attributes or inversion. However, reservoir prediction in sparse well areas poses great challenges due to insufficient well control. If the quality of seismic data is poor, the spatial distribution characteristics of reservoirs cannot be effectively characterized through inversion or attribute analysis, which seriously affects the prediction accuracy. This paper proposes a new method to solve the difficulty in reservoir prediction of oilfields with sparse data and poor quality seismic cube, which evolves from depositional models, forward stratigraphic modeling (FSM) to geocellular modeling. First, based on the comprehensive analysis of core, seismic, grain size, heavy minerals, dip data, it is believed that a special fan delta developed in the Miocene strata in the south of Albert Basin. The reservoirs are dominated by distributary channels, which are in medium-coarse grains, and the provenance is from the southwest to flowing to the northeast. The formation thickness of the stratum decreases from the boundary fault to the direction of the basin. Then, the input parameters of FSM modeling are quantitatively expressed based on the sedimentary model research, including model boundary conditions, basic input information, sediment supply and transportation. FSM results were used to quantitatively characterize the deposition process. The FSM simulation results are compared with the depositional model and well data to verify the reliability. Finally, the shale content model in FSM results is resampled to the geocellular grids and used as the constraint for facies model and property model in geological modeling. This model is used for well pattern design and optimization. This new approach integrates the conceptual depositional model with quantitative FSM results. It improves the accuracy of reservoir prediction and provides a new technical workflow for reservoir characterization. Furthermore, it helps to obtain more insight into the sedimentary process and reduces the risk of oilfield exploration and development.

scholarly journals Effects of transpression on the rocks exposed at the Jhelum Fault Zone in the east of Potwar Basin, Pakistan: implications on the subsurface deformation pattern

2021 ◽  
Author(s):  
Ibrahim Safi ◽  
Gohar Rehman ◽  
Muhammad Yaseen ◽  
Sohail Wahid ◽  
Muhammad Nouman ◽  
...  
Keyword(s):  
Fault Zone ◽  
Stress Component ◽  
Satellite Image ◽  
Fault System ◽  
Deformation Pattern ◽  
The North ◽  
Lateral Extent ◽  
Geological Map ◽  
Potwar Basin ◽  
Well Data

AbstractJhelum Fault is the north–south-oriented major structural lineament originating from the Hazara-Kashmir Syntaxis and extending southwards towards the Mangla Lake. Geographic extent, nature and significance of Jhelum Fault are the subjects which have been approached by different researchers in the past. The previous research provides enough evidence for the presence of Jhelum Fault as well as they discourse its surface extent. None of the previous research addresses the subsurface model of this fault; consequently, its surface extent has been ambiguous and variably reported. The current research takes into account both the surface lineament as well as the subsurface behaviour of the deformed strata to draft the most reasonable depiction of this fault. Field data were coupled with satellite image of 1.5 m ground resolution to produce the geological map of the study area at 1:25,000 scale. The subsurface model was created along four traverse lines by considering the lateral extent of the structures and their shifting trends on the geological map. The stratigraphic package was taken from the nearby hydrocarbon exploratory well data (Missakeswal-01 well of OGDCL) as no rocks older than middle to late Miocene were exposed in the area. The consistent through-going map extents of many faults in the study area prove that faults are playing the major role in the tectonic evolution of the Jhelum Fault Zone. In the subsurface model, the same faults show very little stratigraphic throw, which signify the major stress component to be associated more with wrenching than pure compression. Therefore, most faults in the area are of transpressional nature having dominant lateral component with relatively smaller push towards west on steeply east dipping faults. The model also shows the positive flower structure with dominantly west verging fault system with few east verging back thrusts. The subsurface proposed model shows that the Jhelum Fault is extendible southwards to the Mangla Lake in the subsurface; however, it acts like a continuous shear zone on the surface where there all the shearing is accommodated by tight refolded fold axes. The east–west shortening does not exceed 14.5% which shows smaller compression in the study area. The 3D model further clarifies the model by showing the consistency of the fault system along strike.

THE NEW ROYAL OIL FIELD: A CASE HISTORY OF THE DISCOVERY AND APPRAISAL OF A SUBTLE, STRATIGRAPHICALLY TRAPPED HYDROCARBON ACCUMULATION IN THE TRIASSIC SHOWGROUNDS SANDSTONE, SURAT BASIN

2003 ◽  
Vol 43 (1) ◽  
pp. 415
Author(s):  
R.J. Willink ◽  
R.L. Harvey
Keyword(s):  
Case History ◽  
Oil Field ◽  
Reservoir Properties ◽  
Incised Valley ◽  
Valley Fill ◽  
History Of ◽  
Lateral Extent ◽  
Original Oil In Place ◽  
3D Seismic Data ◽  
Field Area

The New Royal Oil Field is located in a structural embayment on the eastern flank of the Kincora High, western Surat Basin, Queensland. Hydrocarbons have accumulated in the Middle Triassic Showgrounds Sandstone, specifically in a thin basal fluvial unit, interpreted as part of an incised valley fill deposit, that displays excellent reservoir properties but is highly localised in its distribution. The Showgrounds Sandstone overlies either granitic basement or a veneer of Permian clastics including coals. Whereas the Showgrounds Sandstone is an established hydrocarbon bearing reservoir in a number of structural settings elsewhere in the basin, trapping in the New Royal field is primarily stratigraphic.Since its discovery in November 1995, various exploration techniques and technologies have been applied, including the acquisition of 3D seismic data, in an attempt to understand the trapping mechanism of this field and predict its lateral extent, albeit with mixed success. Twelve wells have now been drilled in the greater New Royal field area, only four of which were successfully completed as oil producers from the basal Showgrounds Sandstone. Production to date totals 1.1 million barrels of oil and reservoir simulation studies indicate that original-oil-in-place was 4.6 million barrels.This case history serves as a timely reminder that despite all the technology now available to the petroleum geoscientist, serendipity still plays an important role in the discovery and successful appraisal of certain hydrocarbon accumulations in the Surat Basin.

Crustal thickness under the Gulf of St. Lawrence, northern Appalachians, from gravity and deep seismic data

1989 ◽  
Vol 26 (8) ◽  
pp. 1517-1532 ◽  
Author(s):  
F. Marillier ◽  
J. Verhoef
Keyword(s):  
Seismic Data ◽  
Bouguer Anomaly ◽  
Crustal Thickness ◽  
Moho Depth ◽  
Crustal Layer ◽  
Reflection Seismic ◽  
Middle Paleozoic ◽  
Lateral Extent ◽  
Well Data ◽  
Lower Crustal

We have determined crustal thickness in the Gulf of St. Lawrence, an area that corresponds to an offset of the main northern Appalachians units. A "complete" Bouguer anomaly was calculated from recent depth-to-basement compilations and sediment densities from well data. The Moho surface was obtained by inverting the Bouguer anomaly, assuming a single density contrast at depth, and using an average depth provided by deep reflection seismic data. The resulting crustal model shows a Moho depth of 42–44 km beneath the Grenville Craton, north of the Appalachian deformation front. South of this front, the depth to Moho displays a pronounced thinning of the crust beneath the Carboniferous Magdalen Basin. This is in striking contrast to the deep seismic data, which give a Moho depth of about 43 km. The modelling of the Bouguer anomaly in the Magdalen Basin, taking into account the seismic reflection and refraction data, reconciles these different results and suggests that a 43 km deep Moho beneath the basin is associated with a lower crustal layer about 13 km thick, with high velocity (7.35 km/s) and density (3.05 g/cm3). The Bouguer anomaly suggests that the lateral extent of this high-density layer is confined roughly to the Magdalen Basin. We suggest that this layer is due to mantle underplating of the crust as a result of the Carboniferous-age formation of the Magdalen Basin, and that it is not a feature related to the early to middle Paleozoic development of the Appalachian Orogen.

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