The field X is a brown heavy oil field producing under strong bottom water drive since the mid-1980. Production is from a combination of Amin aeolian and Al Khlata glacial reservoir sediments. At present, the development is focused on drilling horizontal infill wells. One of the biggest challenges is the unfavorable mobility contrast between the heavy oil and water causing early water breakthrough.
The Amin Formation, the primary reservoir, is characterized by a high net to gross ratio and an average porosity of 30 %. However the initial hydrocarbon saturation at the same porosity often varies by 20 % in different parts of the field. Furthermore, core measurements show an order of magnitude scatter in permeability at the same porosity, indicating the presence of different facies. In early studies these variations were attributed mainly to the grain size variations. A later petrographical study found that the abundance of clays and feldspars could also severely reduce permeability, but may retain high porosity.
In the current Study it was found that the rocks have variable radioactivity due to the presence of radioactive Potassium isotope associated with feldspars. A fare correlation was observed between the grain size and the content of feldspars from core. A novel approach to reservoir characterization integrating core and logs was developed leading to a major breakthrough in the reservoir characterization including:
• Enhanced permeability prediction using normalized Gamma Ray (GR) log as 3rd parameter;
• Facies identification using normalized Gamma Ray cut-off;
• Facies based Saturation-Height models.
This work is a good example of advances in reservoir characterization achieved by integrating core and log data. It results in better understanding of reservoir properties distribution, optimization of completions of new wells and improvement of further development scenarios. In particular, abnormally high gross production and high water cut in the north of the field is currently in line with new facies scheme.
Transverse fractures created from horizontal wells are a common choice in tight and shale gas reservoirs. Previous work has shown that proppant pack permeability reduction due to non-Darcy flow in a transverse fracture from a horizontal well causes significant reduction in the fracture performance when the gas formation permeability exceeds 0.5 md. There are other configurations and architectures such as aligning the well trajectory with the fracture, either by drilling horizontal wells in the direction that results in longitudinal fractures or by just sticking with drilling vertical wells. However, when drilling and fracturing costs are considered, productivity is not the only optimization consideration.
The field example illustrates a case when the apparent choice to use transverse fractures from horizontal wells proved to be suboptimal from the productivity perspective, but fundamental considering economics. Parametric studies for permeability ranging from 0.01 to 5 md illustrate the importance of economics in addition to physical performance. For similar reservoir characteristics, the optimum fractured well architecture varies considerably, and therefore an extensive reservoir engineering approach may be necessary beyond the well completions and/or current prejudices and inadequate understanding.
Excessive water production from unwanted zones in oil producing wells is one of the major challenges faced by the oil industry. The applicability of organically crosslinked polymer (OCP) systems as sealants for water shutoff treatments in temperatures up to 350°F is well documented. However, their effectiveness at temperatures above 350°F has not been evaluated. This paper presents experimental data from using an OCP system for water shutoff treatments at 400°F.
At temperatures around 400°F, crosslinking is expected to happen faster and can lead to premature gelation of the recipe before the entire treatment is in place. Thus, controlling the gelation time at such temperatures is extremely crucial. Optimizing the amount of retarder is essential to provide adequate time for placement of the treatment fluid. This paper provides gelation time data at temperatures between 350 and 400°F with different amounts of retarder. With an optimum amount of retarder, the OCP showed a gelation time of 1 hr 20 min.
This paper also describes the experimental setup used to study and determine the long-term stability of the OCP system at 400°F. Sand packs measuring 1-ft long were used for the test to simulate formation conditions. Once the optimized OCP recipe was gelled inside the sand pack, measurements were taken by gradually applying incremental differential pressure (?P) to evaluate the sealant at temperature, as well as the threshold ?P the system could withstand. Even after one month at 400°F, the OCP recipe was able to sustain a ?P of 950 psi over the sand pack.
The data indicates the applicability of this system as an effective conformance product to shut off water-producing zones over an extended period of time at 400°F.
Cinar, Yildiray (The University of New South Wales) | Arns, Christoph (The University of New South Wales) | Dehghan Khalili, Ahmad (The University of New South Wales) | Yanici, Sefer (The University of New South Wales)
Resistivity measurements play a key role in hydrocarbon in place calculations for oil and gas reservoirs. They are a direct indi-cator of fluid saturation and connected pore space available in the formation. Carbonate rocks, which host around half of the world's hydrocarbons, exhibit a wide range of porosities with scales spanning from nanometres to centimetres. The often sig-nificant amount of microporosity displayed by Carbonate rocks emphasizes the necessity of an adequate characterization of their micro-features and their contribution to hydrocarbon in place. In this paper we examine upscaling methods to probe for-mation factor of a fully saturated carbonate sample using an X-ray CT based numerical approach and compare to experimental measurements.
Three-dimensional high-resolution X-ray CT enables the numerical calculation of petrophysical properties of interest at the pore scale with resolutions down to a few microns per voxel. For more complex and heterogeneous samples however, a direct calculation of petrophysical properties is not feasible, since the required resolution and a sufficient field of view cannot be obtained simultaneously. Thus an integration of measurements at different scale is required. In this study a carbonate sample of 38mm in diameter is first scanned using the X-ray CT method with a resolution of 26µm. After accompanying experimental measurements on the full plug, four 5mm plugs were drilled vertically from this sample and X-ray CT images of these plugs acquired at resolutions down to 2.74 µm. We calculate the porosity of the sample (macro- and micro-porosities) using the phase separation methods and then predict the formation factor of the sample at several scales using a Laplace solver. The formation factor is calculated by using a general value of m=2 as cementation factor for intermediate porosity voxels. We compare to experimental measurements of formation factor and porosity both at the small plug and full plug scale and find good agreement.
To assess the degree of uncertainty of the numerical estimate, we probe the extent of heterogeneity by investigating the size of a representative elementary volume (REV) for formation factor. We find that for the considered heterogeneous carbonate sam-ple, formation factor varies considerably over intervals less than a centimetre. Our results show that this variation could be explained by different cementation exponents applied at the micro-voxel scale, with the exemption of one plug, for which the cementation exponent would have to be unreasonably low. These cementation factors are derived by direct comparison be-tween numerical simulation and experiment. We conclude that for one plug an error in experimental measurement might have occurred. The numerical approach presented here therefore aids in quality control. Excluding this plug in the upscaling proce-dure improves the agreement with the experimental result for the whole core while still underestimating formation factor. Al-lowing for a constant m=2 in the simulation at the small scale and using directly the resulting relationship between porosity and formation factor in the upscaling process leads to an overestimation of formation factor.
A multilateral (MLT) well with an advanced intelligent completion string was recently completed in the Middle East. The well was designed as a "stacked?? dual producer in the upper and lower reservoir, and was drilled using the latest geo-steering techniques to accurately place the wellbore in a highly faulted and geologically complex structure. Rotary-steerable drilling systems (RSS) were used in several of the hole sections, along with advanced logging-while-drilling (LWD) tools including multi-pole acoustic, azimuthal deep resistivity, and resistivity at bit. Encounters with unstable shale and faults made the drilling difficult, but the decisions made in real-time to navigate the well resulted in a very high percentage of net pay in both laterals.
This well combined TAML Level 4 multilateral (MLT) technology with passive inflow control devices in the laterals and an advanced intelligent completion system in the mainbore. The TAML Level 4 multilateral junction was cemented to isolate unstable shale above the reservoir and to provide zonal isolation from the lateral completions, which were compartmentalized into stages with proprietary swellable packers and inflow control devices (ICDs). The intelligent completion was run in the mainbore with two interval control valves (ICVs) and isolation ball valve (LV ICV) to manage the production from each of the two laterals independently. The ICVs and LV ICV are controlled hydraulically through four control lines to surface, which were run in a flat-pack with one electric line to control a downhole gauge package for each lateral. Finally, the well was configured to allow the installation of a large electric submersible pump (ESP) to be run inside the upper 9-5/8-in. production tubing.
This project required intensive planning and coordination for more than a year in advance, which made the project successful despite the difficult drilling conditions and resulted in very little NPT for wellbore construction operations. This paper will focus on the planning, execution and lessons learned from the project.
In the existing horizontal wells in the target sand reservoir of the target field, premature water breakthrough caused the water cut trend to increase within months of production. . This occurred because the reservoir has a very high permeability sands along with active faults containing high viscous reservoir fluids.
New technologies were required to overcome the issue, maximize reservoir contact and enhance a more uniform oil production from a single location. Introducing the smart TAML Level-4 MLT well design to this reservoir along with inflow control device (ICD), inflow control valve (ICV), isolation ball valve (LV ICV) and other downhole gauges proved to be the optimum solution. It also aided in managing the production and the reservoir proactively to achieve maximum oil recovery. Moreover, drilling several laterals from a single wellbore with the ability to control production from both laterals had a great economic advantage because of the optimized cost effective field management.
During recent years there has been a significant increase in the use of filter cake removal systems that involve in-situ release of formic or lactic acid during the clean-up stages of the reservoir section, particularly in limestone formations. Furthermore, there have been opportunities to compare the field performance of these relatively small applications of weak, organic acids with significantly larger application volumes of highly concentrated hydrochloric acid (HCl). Surprisingly, some results showed that the smaller volumes of the weaker, organic acids could have equivalent or better performance than that produced by the more traditional HCl-based treatments. In particular this relationship was also observed in cases where the volume of HCl applied had significantly greater power to dissolve limestone than was the case for treatment with the more successful organic acid.
It is well known that productivity of wells in carbonate reservoirs is usually greatly improved by treatments designed to remove the filter cake and the low-permeability zone created by the drilling process, but it is not obvious why smaller volumes per foot of weak organic acid should be more effective than larger volumes per foot of stronger and more concentrated mineral acid.
It has been observed that the acid precursors which release the in-situ acids are applied to the formation in a neutral condition. The paper discusses the implications of using neutral acid precursors, and laboratory data is presented showing the effects of such treatments on the near-wellbore matrix permeability.
Mishra, Prasanta Kumar (Kuwait Oil Company) | Al-Harthy, Abdulrahman (Target Oilfields Services) | Al-Kanderi, Jasem M. (Kuwait Oil Company) | Al-Raisi, Muatasam (Target Oilfields Services) | Al-Alawi, Ghaliah (Target Oilfields Services) | Alhashmi, Salim (Target Oilfields Services) | Turkey, Shaikha (Kuwait Oil Company)
This paper presents the main steps of rock-typing workflow and the technique applied to estimate permeability.
Reservoir rock typing (RRT) is a process of up-scaling detailed geological and petrophysical information to provide more accurate input for 3D geological and flow simulation models. The reservoir rocks that correspond to a particular rock type should have similar rock fabric, pore types and pore throat size distribution. The study integrated multi-scale data types to develop a robust and predictable rock type scheme. This consists of detailed sedimentological description of depositional environment and associated sedimentary features, detailed numerical petrographic analysis of rock texture, grain types, porosity types and rock mineralogy and petrophysical data grouping using openhole log and core plugs porosity-permeability relationship and pore throat size distribution (MICP).
The main objective was to develop a reliable reservoir rock type scheme that captures the heterogeneity in Jurassic carbonate reservoir for the Middle Marrat Formation in South East Kuwait area and implementation of the RRT to the permeability prediction within the field. Integration of the thin sections, porosity-permeability, pore throat size and distribution has resulted in the identification of reservoir rock types. A total of 14 different rock types were identified within the reservoir interval in the cored wells, which is subsequently grouped into eight due to modelling limitation. The RRT up-scaling was done in a way to minimize the impact of grouping on permeability and saturation computations. The prediction success between the cored RRT and the predicted RRT using openhole data is more than 85%. As a result, the permeability computation success between core plugs and computed permeability using the RRT is more than 80%.
Oil or gas effective and relative permeabilities can be reduced to a great extent due to the invading liquid phase of the drill-in or completion fluid, contrary to the misconception that formation damage is less of a concern in lower permeability reservoirs (e.g., less than 5 md). Many laboratory, well logging, and formation tester data proved that mud filtrate (both from water- and oil-based muds) can deeply invade the formation enhanced by capillary forces. This will result in reduction of the oil or gas effective permeability, especially if the formation exhibits fluid emulsion blocks and phase trapping. Unfavorable interaction of the filtrate with the reservoir fluids and rock minerals can generate emulsions and precipitates. The same scenario may occur in hydraulically fractured formations.
An integrated multidisciplinary approach is pursued in this study to evaluate formation damage/remediation potential of low permeability reservoirs. The techniques involve different formation evaluation methods including core analysis, well logging, and well testing along with various cleanup scenarios. Furthermore, results from petrographic analysis and laboratory experiments (Micro and Macroscopic scales) are related and correlated with the larger Mesoscopic and Megascopic scales of well logs and well testing, respectively.
Results of these efforts lead to the following technical contributions; a) Delineation of the low permeability heterogeneous reservoirs, e.g. the Leduce carbonates, into their hydraulic units. b) Determination of the undamaged formation absolute and relative permeabilities along with the diameter of filtrate invasion. c) A rule of thumb is to minimize or prevent damage from taking place by selecting a drilling fluid that quickly forms an easily removable mudcake. d) Cleaning up damage due to water filtrate may be accomplished by just flowing the well and can be accelerated using solvents or surfactants. However, once the formation reaches its irreducible water saturation, remediating water saturation below the irreducible value may not significantly improve its permeability.
Facies modeling forms an integral part of geological numerical modeling. Over the last two decades, different facies modeling methods have been developed using geostatistical algorithms. Most of these methods rely on the assumption of discrete or binary modeling during which each model cell is assigned a single facies. In this study, the size of the cells is on average 100 meters by 100 meters laterally by one meter thick. Based on comparisons to outcrops and subsurface data, such cells should, in fact, include a mixture of facies.
The discrete-facies approach assumes a single facies per cell. The distribution of the facies between wells is described using classical categorical geostatistical algorithms. Reservoir properties are then populated by facies within mapped environments of deposition. This process is well-established and straightforward, especially with regard to tying well data, handling property trends, and applying net rock cut-offs.
A mixed-facies approach can be performed using effective property modeling in which multiple small, fine-scale models are built for each environment of deposition. These models are re-sampled to the full-field cell volume using static and flow-based upscaling methods. The resulting statistics are then used with geostatistics, conditioned to the proportion of each facies present, to populate the full-field model. Such models allow the incorporation of core-scale heterogeneity potentially important in improved oil recovery projects, and may reduce modeling cycle times, especially when multiple iterations are required, such as during history-matching or uncertainty analysis.
This paper compares the impact on simulated fluid flow of modeling facies using discrete modeling versus a mix of facies per cell. Shoreface and subordinate fluvial environments of deposition facies, and five reservoir lithofacies, were modeled.
Fluid-flow simulation of the mixed-facies model, under both primary depletion and pressure maintenance conditions, was smooth and uniform, with a highly conformable flood front. The discrete model was more stratified, with faster and less conformable water movement.
The assignment of discrete facies to large model cells (few hundred meters laterally & few meters vertically) takes less time than a mixed-facies approach and does a better job of preserving organized extremes of permeability important at the production timescale. In the early stages of field development, when there is much uncertainty and a rapid, scenario-based modeling approach is desirable, the discrete approach can be used to flag heterogeneity-related risks more quickly and confidently than the mixed-facies technique. Inaccuracies in performance parameters resulting from the assignment of unscaled discrete values can be corrected using fine-scale sector models tailored to the highest risk cases.
The purpose of history matching is to achieve geological realizations calibrated to the historical performance of the reservoir. For complex geological structures it is usually intractable to run tens of thousands of full reservoir simulation to trace the most probable geological model. Hence the inadequacy of the history-matching results frequently leads to poor estimation of the true model and high uncertainty in production forecasting. Reduced-order modeling procedures, which have been applied in many application areas including reservoir simulation, represent a promising means for constructing efficient surrogate models. Nonlinear dimensionality reduction techniques allow for encapsulating the high-resolution complex geological description of reservoir into a low-dimensional subspace, which significantly reduces number of unknowns and provides an efficient way to construct a proxy model based on the the reduced-dimension parameters.
Polynomial Chaos Expansions (PCE) is a powerful tool to quantify uncertainty in dynamical system when there is probabilistic uncertainty in the system parameters. In reservoir simulation it has been shown to be more accurate and efficient compared to traditional experimental design (ED). PCEs have a significant advantage over other response surfaces as the convergence to the true probability distribution is proved when the order of the PCE is increased. Accordingly PCE proxy can be used as the pseudo-simulator to represent the surface responses of the uncertain variables. When the objective and constraints of a reservoir model is described by multivariate polynomial functions, there are very efficient algorithms to compute the global solutions. We have developed a workflow at which incorporates PCE to find the global minimum of the misfit surface and assess the uncertainty associated with. The accuracy of the PCE proxy increases with the additional trial runs of the reservoir simulator.
We conduct a two dimensional synthetic case study of a fluvial channel as well as a real field example to demonstrate the effectiveness of this approach. Kernel Principal Component Analysis (KPCA) is used to parameterize the complex geological structure. The study has revealed useful reservoir information and delivered more reliable production forecasts.
PCE-based history match enhances the quality and efficiency of the estimation of the most probable geological model and improve the confidence interval of production forecasts.