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.
Africa (Sub-Sahara) A drillstem test was performed on the Zafarani-2 well--located about 80 km offshore southern Tanzania. Two separate intervals were tested, and the well flowed at a maximum of 66 MMscf/D of gas. Statoil (65%) is the operator, on behalf of Tanzania Petroleum Development Corporation, with partner ExxonMobil Exploration and Production Tanzania (35%). The FA-1 well--located in 600 m of water in the Foum Assaka license area offshore Morocco--was spudded. The well targets Eagle prospect Lower Cretaceous resources. Target depth is 4000 m. Kosmos Energy (29.9%) is the operator, with partners BP (26.4%),
Cinar, Yildiray (University of New South Wales) | Neal, Peter R. (University of New South Wales) | Allinson, William G. (University of New South Wales) | Sayers, Jacques (University of Adelaide and Geoscience Australia)
This paper presents geoengineering and economic sensitivity analyses and assessments of the Wunger Ridge flank carbon capture and storage (CCS) site. Both geoengineering and economics are needed to derive the number of wells required to inject a certain amount of CO2 for a given period.
A numerical reservoir simulation examines injection rates ranging from 0.5 to 1.5 million tonnes of CO2 year for 25 years of injection. Primary factors affecting the ability to inject CO2 include permeability, formation fracture gradient, aquifer strength, and multiphase flow functions. Secondary factors include the solubility of CO2 in the formation brine, injection well location with respect to the flow barriers/low-permeability aquifers, model geometry including faults, grid size and refinement, and injection well type. Less significant factors include hydrodynamic effects.
The economics are assessed using an internally developed technoeconomic model. The model optimizes the CO2 injection cost on the basis of geoengineering data and recent equipment costs. The overall costs depend on the initial costs of CO2 separation and source-to-sink distances and their associated pipeline costs. Secondary cost variations are highly dependent on fracture gradient, permeability, and CO2 injection rates. Depending on the injection characteristics, the specific cost of CO2 avoided is between AUS 62 and 80 per tonne.
Australia's fossil-fuel fired power plants emit 194 million tonnes of CO2 each year (Mt CO2/yr), and approximately 26 Mt/yr of this comes from southeast Queensland. A multidisciplinary study has recently identified the onshore Bowen basin as having potential for geological storage of CO2 (Sayers et al. 2006a). In that paper, geological containment and injectivity and reservoir engineering simulation sensitivities showed that a target injection rate of 1.2 Mt CO2/yr over a 25-year project life span could be achieved (i.e., equivalent to injecting the emissions from a 400 MW gas based power station). This study further examines reservoir engineering and economics sensitivities.
This paper presents geo-engineering and economic sensitivity analyses and assessments of the Wunger Ridge flank Carbon Capture and Storage (CCS) site.
A numerical reservoir simulation examines injection rates ranging from 0.5 to 1.5 million tonnes of CO2/year. Primary factors affecting the ability to inject CO2 include permeability, formation fracture gradient, and multiphase flow functions. Secondary factors include the solubility of CO2 in the formation brine, injection well location with respect to the flow barriers/low-permeability aquifers, model geometry including faults, grid size and refinement, and injection well type. Less significant factors include hydrodynamic effects.
The economics are assessed using an internally developed techno-economic model. The model optimises the CO2 injection cost based on geo-engineering data and recent equipment costs. The overall costs depend on the initial costs of CO2 capture and on source-to-sink distances and their associated pipeline costs. Secondary cost variations are highly dependant on fracture gradient, permeability and CO2 injection rates. Depending on the injection characteristics, the specific cost of CO2 avoided is between A$30 and A$44 per tonne.
This paper will detail how a mature oil field in the South Kalimantan region of Indonesia was revitalised by the use of hydraulic fracturing. The Tanjung Raya field is a complex, multilayered, mature oil field. This field was initially developed in the 1960's, with production peaking at over 55,000 bopd. By the mid 1990's, production had declined to less than 1,200 bopd. The introduction of a water flood increased production to a peak of 10,000 bopd, but this quickly declined at an average rate of circa 33% per year. With the introduction of a fracturing programme, based on treating existing and new wells, production has been maintained at a flat 7,000 bopd over the past two years. The hydraulic fracturing program has accounted for 80% of these significant production gains, adding more than 5.7 million barrels of recoverable reserves and extending the economic life of the field by more than 2.5 years.
Hydraulic fracturing is a process that is relatively underutilised in the Asia-Pacific region, as compared to North America, Latin America and the Middle East. With a couple of recent noticeable exceptions, the technique is either not considered during field development and redevelopment, or it is used on a one-off, remedial basis. However, fracturing can be an integral part of well design, and an effective tool when the technique is applied systematically by practitioners who understand its capabilities; as demonstrated in the Tanjung Raya field.
This paper will discuss how a significant increase in oil productivity from a mature field was attained with a very high propped fracture treatment success rate. It will also detail how the correct design of fracture treatments can enhance reservoir recovery rates, and fully utilise vertical wells as a low cost, effective alternative to horizontal wells, or to increase well spacing. The paper will also discuss the most significant issues of implementing such a program and how these issues were effectively dealt with in the Tanjung field.
The Eromanga Basin is an established Australian producing region with oil and gas found in several different Formations. At the request of an Operator, a project was undertaken to construct saturation-height functions for all the Eromanga reservoir units with a secondary objective being to define residual hydrocarbon saturations.
Initial investigations revealed many reservoirs with residual hydrocarbon columns, the significance of which had not been well understood. The residual hydrocarbons implied that imbibition, rather than drainage, capillary pressure curves were representative of water saturations in the reservoir. This insight suggested higher oil-in-place and reserves volumes than previously assumed since mobile hydrocarbons are present very close to the pressure derived Free-Water Level in imbibition systems.
When individual hydrocarbon Fields were considered, there were insufficient special core analyses to derive meaningful residual hydrocarbon or saturation-height relationships. However, on the basin scale, a significant volume of measurements had been acquired over a period of 22 years, albeit using different laboratories and a variety of measurement techniques. With knowledge of the measurement techniques and Formations sampled, the data were combined in such a way that consistent datasets were obtained for end-point relative permeabilities and drainage and imbibition capillary pressure curves.
Interpretation of these datasets produced residual oil saturation and drainage and imbibition saturation height relationships. These relations were tested against those log-derived water saturations considered most reliable by the Operator, showing excellent matches. The model developed successfully described the water saturation distributions in the reservoirs tested in a manner not previously possible. Indeed, the use of the drainage and imbibition saturation-height functions together with residual hydrocarbon relationships provides a powerful tool to determine both static and dynamic fluid contacts, while checking the validity of wireline log-based water saturations.
At the request of an Operator, a review has been undertaken of all the available Special Core Analyses (SCAL) for the Jurassic Oil reservoirs found in the Eromanga Basin of Australia. The primary objective of this study was to construct appropriate saturation-height functions for oil volume quantification and reservoir modelling. A secondary objective was the identification of residual oil saturations from suitable core analyses.
The Jurassic reservoir units involved were the Adori, Basal-Jurassic, Birkhead, Hutton, McKinlay, Murta, Namur and Westbourne Formations.
The Eromanga Basin is an established producing area, with many fields and a large database of wireline log measurements and core analyses collected over more than 20 years.
Despite a number of different Operators and a history of production in the area, the significance of the residual oil found below the pressure derived free-water levels (FWL) of many fields had not been fully recognised.
The signs that imbibition may be significant in reservoirs include:
presence of "residual oil" below the pressure derived FWL at discovery,
dry oil production from close to a FWL,
sharper log-derived transition zones than the reservoir permeability suggests.
In addition, as oil fields are produced, water sweeps through sections of reservoir. These sections have gone or are undergoing water imbibition.
Stochastic interpolation methods for generating input for reservoir simulations require accurate models for spatial variability. New models based on fractional Levy motion, a generalization of fractional Brownian motion, have strong empirical support. Stochastic interpolations based on the Levy model have a higher degree of spatial variability compared to Gaussian fractals, In two-dimensional waterflood simulations, the breakthrough curves for the Levy interpolation method are better clustered around predicted production behavior based directly on outcrop data.
Petroleum reservoirs often exhibit heterogeneity over a variety of length scales. This multiscale heterogeneity has a considerable, often dominant, influence on hydrocarbon recovery. Traditional methods for interpolating or extrapolating reservoir properties into unobserved regions have tended to smooth data, thus suppressing the effect of heterogeneity and rendering predictions of reservoir performance inaccurate. In recognition of this smoothing problem, stochastic interpolation methods have been increasingly applied. These methods produce multiple equiprobable maps of the reservoir. Each map matches the measurements at the wells and has statistical properties governed by an imposed theoretical model. Success in reservoir performance prediction depends on the quality of the model in mimicking the spatial variability of sedimentary rock.
One approach to stochastic simulation treats the variations in rock properties as fractional Brownian motion, fBm, or fractional Gaussian noise, fGn. This approach is based on Hewett observation that fluctuations exist over a wide range of spatial scales, and that this is captured in the fBm or fGn models. This attempt to build in some understanding of the quantitative nature of sedimentary rock directly into the model is an appealing alternative to more mechanical approaches. However, the fBm and fGn models are based on an assumption of an underlying Gaussian distribution. This is rarely supported by empirical evidence, except perhaps in some carefully selected examples.
In this paper we summarize recent advances in the understanding of multiple-scale heterogeneity that go beyond the Gaussian-based fractal and achieve greater realism while retaining simplicity. We show how this new model for heterogeneity can be used to generate stochastic permeability maps of reservoirs, and compare the performance of the new method with that of the fBm model.
The new model for heterogeneity characterization is based on observations that incremental values in well logs and permeability sequences are accurately modeled as having Levy-stable probability distributions and that the width of the fitted distribution increases with separation distance in a manner consistent with scaling behavior. This suggests the use of a fractional Levy motion, fLm, model for heterogeneity. fLm can be regarded as a generalization of fBm.
Levy distributions have power-law tails Pr for large q and 0 < < 2, which leads to diverging theoretical moments, including the variance. These slowly decaying tails make the Levy distributions useful for modeling systems with a high degree of spatial variability. The slowly decaying tails in the distribution of incremental values correspond to the occasional sharp property contrasts or "big jumps" in property values associated with stratification. The use of this model does not require rock properties to actually have an infinite variance distribution. It is a useful approximation when power-law tails exist over a large but finite range, which for practical purposes gives the underlying distribution properties similar to those of an infinite variance distribution.
We conducted simulations of two-dimensional waterfloods to test the performance of the interpolation based on fractional Levy motion, and compared the results with other interpolation methods. The idealized waterfloods are intended to illustrate the effects of heterogeneity while avoiding complicating effects such as gravity, compressibility and viscosity contrasts. To further test our simulation technique, we make use of a detailed permeability map of a sandstone outcrop.
This paper describes the evolution and field application of fracture stimulation techniques applied to the Murta reservoir in South Australia, where unique conditions govern fracture stimulation design. The use of a minimum viscosity pad fluid has been shown to provide effective fracture pad fluid has been shown to provide effective fracture height growth constraint and provide for efficient fracture length propagation, resulting in increased productivity index improvement.
Fracture stimulation has proved to be a viable technique to allow economic exploitation of this resource, while allowing its continual appraisal.
The Murta member is an oil bearing sandstone, widespread throughout the Eromanga basin in South Australia and Queensland. The Murta member cannot be adequately described by conventional petrophysical analysis due to its thinly laminated nature. The evaluation of the poorer quality wells requires production performance. Completing the well risks capital which may yield an inadequate return. Fracture stimulation techniques have been applied to the reservoir and are shown to result in up to a 6 fold increase in productivity index.
Fracture stimulation is the only viable method of improving productivity as the Murta member is a low permeability productivity as the Murta member is a low permeability formation with a reasonably large gross oil column of 100-125 ft [30-38 m], even though the net pay to gross height ratio is relatively low. This paper shows the evolution of fracture stimulation techniques applied to Murta wells. The optimisation of fracture treatment design is complicated by the inability to accurately quantity key reservoir parameters such as reservoir permeability. Optimisation of parameters such as reservoir permeability. Optimisation of fracture stimulation treatment design has relied mainly on field experience. Obstacles to the optimisation of the design, such as unconstrained height growth, have been identified and the techniques applied to control these potential problems have resulted in increased productivity potential problems have resulted in increased productivity index gains. Treatments use a small volume of thin pad fluid and place about 50 000 lbm [22 600 kg] of proppant in the formation. This technique ensures that the proppant is transported to the limits of fracture extension to efficiently prop the created fracture length while minimising height growth.
The paper is organised in the following way. Firstly there is a statement of the problem. The reservoir characteristics and the difficulties of petrophysical evaluation are described. A historical overview is given. followed by presentation of the data collected and the methods used. presentation of the data collected and the methods used. Interpretation of the data and application of new ideas including case studies follows.
STATEMENT OF THE PROBLEM
Conventional evaluation of the Murta reservoir indicates that many wells may not yield adequate return on investment if completed. Uncertainty exists as to the volume of original oil in place and the potential recovery factor due to the difficulties of log evaluation and ambiguities of open hole DST results. The Murta member is known to be oil bearing with reasonably large gross oil column. Therefore the key problem is to achieve adequate oil productivity from the well. Successful stimulation would encourage the development of the extensive Murta resource.
Fracture stimulation appears to be a promising technique to achieve significant productivity improvement. To maximise the economic benefits of fracture stimulation, the reservoir deliverability, fracture mechanics, fracturing fluid nature and proppant transport mechanism must be considered.