Volumetric Uncertainties Research Articles

Reservoir Quality and Flow Unit Characterization of a Reservoir in X Field, Baram Delta

Reservoir stratigraphic continuity are uncertainties that may be due to lack of facies association definition in reservoirs. These uncertainties come into play where proper porosity–permeability (poroperm) evaluation is misrepresented, leading to volumetric estimation uncertainties. Most oil fields in the Baram Delta have been previously studied with the development of static models. The lack of sequence stratigraphic input in the study was due to constraints including fault shadowing and gas chimney presence which deterred the volume estimations. Earlier interpretation of facies distribution and depositional environment of a field, named X, was achieved mainly by using core descriptions and interpretations. In this study, a reinterpretation of the depositional environment and facies distribution were carried out in the R1 and R2 reservoirs. The analysis was done by incorporating the depositional environment and facies with newly interpreted facies comprising of sand, silty sand, sandy shale and shale facies, created using neural network programme. Utilising newly set facies definitions with additional inputs including porosity and permeability data, a better facies distribution for the reservoir is emplaced. With the facies definitions set for 3 wells, the reservoir quality was investigated through poroperm relationship, reservoir quality index (RQI) and fluid flow unit interpretation. The new definitions for reservoir facies consequently matched well to the core descriptions. The R1 reservoir facies-poroperm relationship were clustered well with respect to each facies type. The RQI was then evaluated from the permeability and porosity values for all the selected wells. The fluid flow units were estimated using depth interval difference, effective porosity and permeability data. The fluid flow regimes are different for all the wells, where the updip Well B displayed significantly better flow capacity than both Well C and Well A. However, Well C also displayed good fluid flow capability, indicated by high gradient flow capacity over storage capacity, although with presence of some layers of poor flow quality. Good communication for the downdip wells provides a potential for lateral fluid flow component which can influence the storage and flow capacity of fluid in the updip Well A, and thus creating an overall control and validation of fluid capacity in the reservoir.

Pilot Point Optimization of Mining Boundaries for Lateritic Metal Deposits: Finding the Trade-off Between Dilution and Ore Loss

Geological contacts in lateritic metal deposits (footwall topographies) often delineate the orebody boundaries. Spatial variations seen in such contacts are frequently higher than those for the metal grades of the deposit. Therefore, borehole spacing chosen based on the grade variations cannot adequately capture the geological contact variability. Consequently, models created using such boreholes cause high volumetric uncertainties in the actual and targeted ore extraction volumes, which, in turn, lead to high unplanned dilution and ore losses. In this paper, a method to design optimum ore/mining boundaries for lateritic metal deposits is presented. The proposed approach minimizes the dilution/ore losses and comprises two main steps. First, the uncertainty on the orebody boundary is represented using a set of stochastic realizations generated with a multiple-point statistics algorithm. Then, the optimal orebody boundary is determined using an optimization technique inspired by a model calibration method called Pilot Points. The pilot points represent synthetic elevation values, and they are used to construct smooth mining boundaries using the multilevel B-spline technique. The performance of a generated surface is evaluated using the expected sum of losses in each of the stochastic realizations. The simulated annealing algorithm is used to iteratively determine the pilot point values which minimize the expected losses. The results show a significant reduction in the dilution volume as compared to those obtained from the actual mining operation.

Dynamic nature of supercritical CO2 adsorption on coals

Adsorption on non-rigid solids was shown to be a dynamic process. Excess adsorption and desorption isotherms of CO2 on eight Argonne Premium coal samples were measured at 55 °C and pressures up to 14 MPa by manometric method. The excess adsorption isotherms of CO2 on powdered coals showed almost Langmuir-like to rectilinear shape behavior at low pressures up to 9 MPa, and it increased noticeably at pressures higher than 9 MPa. There was a significant hysteresis between the excess adsorption and desorption isotherms for each rank of coals, which was related to the volumetric uncertainties occurring during the adsorption isotherm measurements. The parameters related to the adsorption capacity and micro porous characteristics of the coal were obtained at different pressure ranges by fitting the experimental data to the modified Dubinin-Astakhov (D-A) equation at the increasingly larger pressure ranges, using only the first 4 data points of the excess adsorption isotherm initially, and progressively using additional data points for the subsequent values. It was shown that the curve fit parameters vary with pressure, and therefore, concluded that the adsorption on non-rigid solids such as CO2 on coal is indeed a dynamic process. It was suggested that new adsorption isotherm equations need to be developed considering the dynamic nature of the adsorption on solid adsorbents.

Graph theory for analyzing pair-wise data: application to geophysical model parameters estimated from interferometric synthetic aperture radar data at Okmok volcano, Alaska

Graph theory is useful for analyzing time-dependent model parameters estimated from interferometric synthetic aperture radar (InSAR) data in the temporal domain. Plotting acquisition dates (epochs) as vertices and pair-wise interferometric combinations as edges defines an incidence graph. The edge-vertex incidence matrix and the normalized edge Laplacian matrix are factors in the covariance matrix for the pair-wise data. Using empirical measures of residual scatter in the pair-wise observations, we estimate the relative variance at each epoch by inverting the covariance of the pair-wise data. We evaluate the rank deficiency of the corresponding least-squares problem via the edge-vertex incidence matrix. We implement our method in a MATLAB software package called GraphTreeTA available on GitHub (https://github.com/feigl/gipht). We apply temporal adjustment to the data set described in Lu et al. (Geophys Res Solid Earth 110, 2005) at Okmok volcano, Alaska, which erupted most recently in 1997 and 2008. The data set contains 44 differential volumetric changes and uncertainties estimated from interferograms between 1997 and 2004. Estimates show that approximately half of the magma volume lost during the 1997 eruption was recovered by the summer of 2003. Between June 2002 and September 2003, the estimated rate of volumetric increase is (6.2 , pm , 0.6) times 10^6~mathrm{m}^3/mathrm{year} . Our preferred model provides a reasonable fit that is compatible with viscoelastic relaxation in the five years following the 1997 eruption. Although we demonstrate the approach using volumetric rates of change, our formulation in terms of incidence graphs applies to any quantity derived from pair-wise differences, such as range change, range gradient, or atmospheric delay.

Model‐uncertainty quantification in seismic tomography: method and applications

ABSTRACTUncertainty is inherent in every stage of the oil and gas exploration and production (E&P) business and understanding uncertainty enables mitigation of E&P risks. Therefore, quantification of uncertainty is beneficial for decision making and uncertainty should be managed along with other aspects of business. For example, decisions on well positioning should take into account the structural uncertainty related to the non‐uniqueness of a velocity model used to create a seismic depth image. Moreover, recent advances in seismic acquisition technology, such as full‐azimuth, long‐offset techniques, combined with high‐accuracy migration algorithms such as reverse‐time migration, can greatly enhance images even in highly complex structural settings, provided that an Earth velocity model with sufficient resolution is available. Modern practices often use non‐seismic observation to better constrain velocity model building. However, even with additional information, there is still ambiguity in our velocity models caused by the inherent non‐uniqueness of the seismic experiment. Many different Earth velocity models exist that match the observed seismic (and well) data and this ambiguity grows rapidly away from well controls. The result is uncertainty in the seismic velocity model and the true positions of events in our images. Tracking these uncertainties can lead to significant improvement in the quantification of exploration risk (e.g., trap failure when well‐logging data are not representative), drilling risk (e.g., dry wells and abnormal pore pressure) and volumetric uncertainties. Whilst the underlying ambiguity can never be fully eradicated, a quantified measure of these uncertainties provides a valuable tool for understanding and evaluating the risks and for development of better risk‐mitigation plans and decision‐making strategies.

Poster — Thur Eve — 39: Dosimetric Evaluation of Bulk Electron Density Based Treatment Planning in IMRT Head and Neck Patients: Can It Be Used for MRI‐Based Planning?

One limitation of using MRI alone for radiation planning is the lack of electron density for dose calculation. We evaluated the dosimetric accuracy of using bulk density overrides as a substitute for CT‐derived densities in IMRT treatment planning for head and neck cancer. Ten clinically‐approved, CT‐based treatment plans were used for this study. Three dose distributions were calculated for each treatment plan. The first calculation used CT‐derived density as a basis for heterogeneity correction. The second calculation assumed a homogeneous patient density of 1 g/cm3. For the third dose calculation we contoured bones and air cavities and assigned them a uniform density of 1.5 g/cm3 and 0 g/cm3, respectively. The remaining tissue was assigned a density of 1 g/cm3. All three calculations utilized identical beam parameters (angles, segments and MUs). Actual MR images were not used for contouring to avoid effects of gradient distortion and volumetric uncertainties associated with them. All calculations were done using the Collapsed Cone Superposition algorithm in the Pinnacle3 treatment planning system. Our results show that the assignment of bulk density to bones and air cavities was a feasible approach to IMRT treatment planning for head and neck patients. In almost all cases, the dosimetric results were within 2% of the treatment plans based on CT‐derived density. This method may overcome the lack of electron density information in MR‐based planning. The use of homogeneous geometry, while simpler and less time consuming, resulted in unacceptably high errors in the dose distribution compared to the nominal plan. This research project is supported by Philips Medical Systems.

Potential Leaks in Hydrocarbon Reservoirs: Costs, Profits and Uncertainties

A potentially leaking reservoir has an uncertainty on the volumetric resources it might contain because one does not know the extent to which it might have leaked nor does one know that it actually does contain hydrocarbons ahead of drilling. The economic aspects of such an exploration opportunity are investigated in this paper, where it is shown that not only do the uncertain volumetric aspects play a role in determining potential profitability but, and often more importantly, so do the potential drilling costs and the future selling price of product, both of which are also uncertain. It is the combined interaction of both the volumetric uncertainties and the economic uncertainties that determine the possible worth of the opportunity. Here we show how to determine the parameters that are most important in contributing to the uncertainty on the potential worth. We also show how to estimate the probability of achieving break-even and how to determine which parameters are causing the greatest uncertainty on the break-even probability. In this way decision-makers in a corporation can determine more effectively where to concentrate their efforts to improve the uncertainty of critical parameters, and they also know which are the critical parameters to be addressed. Time, effort, and money are thus spared by not focusing on parameters that play more minor roles in the assessment of a potentially leaking reservoir as an exploration opportunity.

Uncertainties in Facies Proportion Estimation II: Application to Geostatistical Simulation of Facies and Assessment of Volumetric Uncertainties

Geostatistical simulations of lithotypes or facies are commonly used to create a geological model and to describe the heterogeneities of petroleum reservoirs. However, it is difficult to handle such models in the framework of multiple realizations to assess the uncertainty of hydrocarbon in place. Indeed, the hydrocarbon in place is correlated with the facies proportions, which are themselves uncertain. The uncertainty model of facies proportions is not easy to describe because of closure relationships. A previous attempt was made with a nonparametric approach using the resampling technique. It has been successful in a stationary case but it is difficult to extend it to nonstationary cases. In this paper, we have applied the vectorial beta parametric model or Dirichlet model. It has provided much more realistic uncertainties on volumetrics in very different geological and geostatistical contexts.

Understanding through Seeing - The role of Seismic in an Integrated Study of a Mature Nigerian Field: ABSTRACT

The impact of integration of both data and disciplines is presented in the case of an Nigerian field, with particular emphasis on the central role of seismic data: A pre-requisite for any seismic interpretation is a reliable well-to-seismic tie. Due to log data availability and quality, this match was only achieved by generating synthetic seismograms based on acoustic impedance models. The seismic time interpretation was guided by the geological framework following sequence stratigraphical principles. Depth conversion and evaluation of volumetric uncertainties were based on all data. The resulting STOIIP estimates have been compared to the volumes derived independently from production data. It then became possible to explain apparent mismatches seen in some reservoirs by modifying the best-estimate volumes within the uncertainties and by comparison with analogue reservoirs Channel-like amplitude features encountered in shallow reservoirs helped to explain variable production performance and consequently to identify appraisal and development opportunities. Some of the deeper, shoreface sands seem to behave in a more tank-like manner. This is not only confirmed by recent RST-logs, but also by seismic flatspots. The flatspots are conformable to structure and reflect the remaining oil distribution. These results highlight the value of continuous integration of data and disciplines tomore » the petroleum engineering study.« less