Summary The evaluation of expected ultimate recovery (EUR) for tight gas wells has generally relied upon the Arps equation for decline-curve analysis (DCA) as a popular approach. However, it is typical in tight gas reservoirs to have limited production history that has yet to reach boundary-dominated flow because of the low permeability of such systems. Commingled production makes the situation even more complicated with multiboundary behavior. When suitable analogs are not available, rate-transient analysis (RTA) can play an important role to justify DCA assumptions for production forecasting. The Deep-basin East field has been developed with hydraulically fractured vertical wells through commingled production from multiple formations since 2002. To evaluate potential of this field, DCA type curves for various areas were established according to well performance and geological trending. Multiple-segment DCA methodology demonstrated reasonable forecasts, in which one Arps equation is used to describe the rapidly decreasing transient period in early time and another equation is used for boundary-dominated flow. However, a limitation of this approach is the uncertainty of the forecast in the absence of extended production data because the EUR can be sensitive to adjustments in some assumed DCA parameters of the second segment. In this paper, we used RTA to assess reservoir and fracture properties in multiple layers and built RTA-type well models around which uncertainty analyses were performed. The distributions of the model properties were then used in Monte Carlo analysis to forecast production and define uncertainty ranges for EUR and DCA parameters. The resulting forecasts and EUR distribution from RTA modeling generally support the DCA assumptions used for the type curves for corresponding areas of the field. The study also showed how the contribution from the various commingled layers changes with time. The proposed workflow provides a fit-for-purpose way to quantify uncertainties in tight gas production forecasting, especially for cases when production history is limited and field-level numerical simulation is not practicable.
A heavy oil field (Field X) in Northern Kuwait is in the early stages of development but it is clear from production pilots that tight units (baffles) of variable lithology, thickness and continuity, within the reservoir will play a key role in influencing steam conformance and recovery efficiency. The high well/core density of the field’s production startup area allows re-evaluation of baffles in light of cross-discipline integration of pilot production data, petrophysical data and detailed core review. A process was followed to update and calibrate all core descriptions against logs, follow a consistently picked set of petrophysically defined markers, compare visually defined lithofacies with log defined ones, and then map out key surfaces. The key next step is to define appropriate reservoir properties by facies/rock types, apply these to understanding pilot behaviour and predict steam conformance for Well, Reservoir and Facilities Management (WRFM) and the next phases of the wider field development planning. The field’s baffles play a role far beyond just understanding steam conformance, they are a first barrier for cap rock integrity and their presence/absence will also influence the path and rate of the aquifer influx. The petrophysical redefinition (Baffle Quality Index) of a "semi-stratigraphic" interval - which will stop or slow steam migration depending on its quality and lateral extent - has enabled efficient communication about the baffle, and allowed the wider team of petroleum engineers from a number of subsurface disciplines to focus on dynamic properties impacting recovery – steam conformance, aquifer influx, windows between isolated reservoir units – and then evolve the development strategy, effectively respond to WRFM issues, optimize observation and infill well placement and increase UR in a cost effective way.
Within North Kuwait heavy oil fields, integrated reservoir modelling is challenged by inherent reservoir heterogeneities, regional non-stationarity (i.e. trends), asymmetrical well and seismic distributions, and the need to maintain alignment between various the model scales required and multiple purposes for which the models will be used. This paper presents a number of customized workflows adapted to characterize these reservoir architectures and heterogeneities within one field, appropriately at all model scales and in regions with variable well control. A reliable new rock type classification scheme was derived from cross plot analyses of Gamma Ray and Bulk Density (GR-DENS) logs. Within an initial production area containing over 900 regularly spaced wells, 3D variograms for these lithotypes were estimated, calibrated with 3D seismic and reservoir equivalent surface outcrops. The lithotypes were distributed into full field static models using these variograms and the Sequential Indicator Simulation (SIS) algorithm. An additional declustering step was implemented to express regional trends and account for asymmetrical data distribution. Petrophysical property modeling (shale volume, effective porosity, water saturation) was performed using the Kriging algorithm conditioned to lithofacies. From these full field models, sector models were created to capture geological heterogeneity at a smaller grid increment. Full-field facies were downscaled onto the sector model grids, and then the Sequential Gaussian Simulation (SGS) algorithm was used to interpolate petrophysical properties, constrained by histograms of the kriged background models. This allowed information from wells outside of sector models to be incorporated efficiently into them. The facies and heterogeneities represented within the full-field static models have improved upon earlier versions, by being distributed more consistently relative to known seismic and well control, and to outcrop reservoir analogues. Modelled petrophysical properties also show a more consistent linkage with known values derived from core analyses. This consistent set of models can now be used with greater confidence, to answer questions ranging from in-place volume uncertainties to dynamic production forecasting, to life of field development. This has also led to reduced dynamic model run times, and improved reservoir management and operations optimization. In summary a robust series of full-field and sector models was developed and customized to a North Kuwait heavy-oil field, with information from data-rich areas being elegantly applied to reduce uncertainties in data-poor areas. These nested models can now be matched to the detail required for the model purpose. For example heterogeneities that matter-for-flow in dynamic simulation models can be represented explicitly, whereas for full-field volume estimations property averages can be used.
Objectives/Scope The shallow depth unconventional reservoir in Northern Kuwait is essentially a monoclinal structure. Sediments have undergone significant shallow depth diagenesis, which resulted in selective oil/water accumulation, controlled mainly by lithological variations. Thus, the reservoir can be classified as stratigraphic-dominant trap. A correlation approach required addressing these variations, which can also be well understood by non-geologist, and the scheme should be appropriate for selection of perforation intervals. Methods, Procedures, Process Reservoir sands are in the form of multi-stacked distributary/fluvial channels. Subsequent to sediment deposition, moderate to intense diagenesis took place. The diagenesis resulted in formation of cemented baffles under low reservoir pressure (250psi) regime. For demarcation of bed boundaries, mapping and modelling purpose the reservoir sand, shale, baffles, gas, water, water above oil, this petrofacies classification method is proposed. The method is well capable of defining the various bed boundaries with fluid/gas content in it with confidence. The method developed after extensive core, core data and log calibration and study. More than one thousand wells correlated. Results, Observations, Conclusions The classification method is simple, yet robust to characterise reservoir vs. non-reservoir variations and oil/gas vs. water quite effectively. Cementation activities typically noticed on top/bottom of the units but many times in between the reservoir sand also. We are able to correlate cemented layers across the area. The cementation also gives rise to water perched above oil phenomenon due to relatively higher capillary pressure in the zone. Oil is migrated post-cementation and occupied reachable pore spaces. Oil also has undergone significant biodegradation because of favourable temperature and restricted nutrient supply. As a result, thin layers of thermal/biodegraded gas also formed locally. The method allows for surface related categorisation representing clean sand, cemented sand, shale, gas/oil/trapped water zones. Novel/Additive Information This unconventional reservoir is being developed with thermal application. Thickness of baffles, barrier, gas, water zones are critical in selection of perforation interval for steam application. This classification method is part of perforation selection for first phase of development and modelling purpose, and it was applied to hundreds of wells, many of them are undergoing production operations successfully.
Routine and Special Core analysis (RCAL and SCAL) are the cornerstone of Petrophysics Modeling and Formation Evaluation. In order to obtain the required information, it is important to have quality core, its processing and analysis. This paper summarizes current practices vis-à-vis improvements made in key technical areas. Coring and core analysis are cost-intensive processes. Only quality data from representative core plugs can offset the high cost and can help to achieve the objectives of coring and core analysis. To obtain consistent quality core plugs, coring practice, on-site handling and plugging procedure have to be the best in class. Coring and core analysis in the shallow-depth Heavy Oil Fields in Northern Kuwait have been in place for some time. The processes like i) coring operation ii) on-site core handling and preservation iii) core slabbing iv) core plugging and finally v) core analysis are continually improved. In order to be efficient and cost-effective, all the above processes were re-visited, quality gaps identified and improvements implemented by incorporating unconsolidated formation characterization from the available extensive petrographic studies. For example in the coring practice front, coring and core handling protocols were modified for sour heavy oil-bearing formations noticed in parts of the fields. On-site dry ice was used in addition to the prevalent practice of normal freezing. In the laboratory analysis front, obtaining representative plugs and getting useful results from them were the key challenges. Compared to the previous practice of liquid N2 injection from top only during core slabbing by band saw, liquid N2 injection from both top and bottom resulted in improved core integrity. The previous practice of plunge cutting of plugs with liquid N2 was continued. Before any analysis, Computer Tomography (CT) scan of the plugs was performed to discriminate plug-integrity related issues. This paper discusses lessons learnt from past coring and core analysis processes and their impact on heavy oil development. Improvements to these processes as cost-effective measures are presented through real examples. Recommendations for improvement include field procedure, laboratory process, and usability of the tests performed, which may be useful to the industry where heavy oil core analysis is used.
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