TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractAn extensive petrophysical analysis has been carried out on a study well in a giant carbonate field in the Lower Cretaceous of Abu Dhabi. The well was cored, and a comprehensive log suite recorded including: Nuclear Magnetic Resonance (NMR), Borehole Imaging, Shear Sonic and Mineral Spectroscopy in addition to the more normal logs.A high-resolution permeability profile was measured on the core. Plugs taken every foot were supplemented by minipermeameter measurements every inch. While this profile captures high frequency variability it is limited in its applicability to predicting reservoir behavior. Analysis of large scale flow unit permeability is better assessed with dynamic data.A number of advanced log based permeability estimators were developed in an attempt to match the core permeability profile. The estimators are based on NMR, image analysis and Stoneley measurements among others. This paper presents a comparison of these predictors to the core and makes recommendations as to the preferred permeability prediction methods for this field.For this well the Stoneley permeability correctly predicted a trend decrease of permeability with depth but failed to honor the full extent of the trend. As expected, given its vertical resolution, it also failed to respond adequately in the more heterogeneous intervals.A method based on a mean NMR T 2 measurement gave a good general match to the data, but again lacked vertical resolution. An electrical image based method brings an important improvement in sensitivity to the small-scale variations in permeability, but in some places failed to follow the lower frequency trends.A composite method using the NMR to supply the overall trend, and the image to provide the higher resolution, gave the best match to the core permeability profile available from the tool suite, which was run. The method is a modification of the well-established SDR permeability equation. A new term is introduced to account for the contribution of connected vugs, which are responsible for the high permeability intervals in this well.The logs used in the methods described here do not make direct measurements of permeability. Instead permeability is inferred indirectly from measurements sensitive to parameters such as texture and pore size. It is doubtful that a single methodology based on such measurements can provide a "universal" permeability estimator fitting all cases. The methods presented here should be applied with care and will benefit greatly from calibration to spot permeability data.The method has particular application in high cost environments where a good permeability is required along the wellbore but the cost and rig time required for continuous whole coring cannot be justified.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractOne of the most challenging issues within Abu Dhabi onshore fields is the definition, characterization and modeling of the main structural heterogeneities. Integration of structural, geometrical and dynamic understanding is the key to defining what is important from a field development and production viewpoint, since it may affect the economics of the fields.A consistent analysis and approach is essential to be able to compare the fields taking into account the three different types of fracture (i.e. faults, fracture corridors and diffuse fracturing), and the potential geological events that postdate the fracturing (fluid circulation, diagenesis).Diffuse fracturing was commonly described across most fields based on core observations and image log interpretation. However, this fracture type alone cannot explain the behavior of many wells.A new look at the data reveals that several fields exhibit fracture corridors and/or subtle faults. Integrating the well behavior suggests this fracture type may have a significant impact in some fields. Unfortunately, this style of deformation is often below the seismic detection threshold.The recent acquisition of 3D seismic across most of the Abu Dhabi onshore fields reveals all fields are faulted at the seismic scale. The fault style is often characterized by small throws. Recent improvements in seismic resolution reveal that what was previously interpreted as one fault is in fact made of numerous fault segments separated by relay areas. This new interpretation has obvious implications for the dynamic behavior of these fault zones. Indeed great discrepancies of the fault zone behavior are observed and discussed using six example fields which encompass a wide variety of carbonate reservoirs with varied depositional environments and reservoir properties. Given such a range of reservoir properties, faults and fractures with similar properties might be expected to have very different expressions in the way they affect fluid flow.
Objective It is challenging to increase oil recovery from a reservoir with a thin oil rim and large gas cap after a long depletion of the gas cap. Gas or water breakthroughs are commonly seen and are responsible for disappointing oil recovery. The development becomes more challenging when resources are needed to control depletion and maintain reservoir pressure. This paper deals with challenges encountered in developing a thin oil rim and compares the recovery of the development scenarios. Methods, Procedures The field under study is an offshore Carbonate reservoir consisting of multiple stacked thin porous layers separated by less porous layers. The gas cap was developed first, as at that time the oil rim was only poorly understood, and its potential was not fully recognized. Oil development only started after a prolonged period of gas depletion. Post depletion, gas injection has been introduced to control the depletion and to permit further development of the oil rim. The process followed in this study is summarized as follows: Results A representative fit for purpose sub-surface model to capture the high reservoir heterogeneities and the dynamic behavior was crucial. It is demonstrated that despite the challenges inherent in this reservoir, it will be possible to increase the oil recovery. A number of locations for new oil production wells are identified and these allow recovery of additional oil through sustainable production. Zones of high CGR in the reservoir are a good target to enhance condensate production. For gas recovery reservoir pressure is the main factor controlling recovery. Novel/Additive Information This paper shows that despite the early depletion of the gas cap there is a room to enhance oil rim recovery of thin oil rim reservoirs underlying extensive gas caps, by means of a development which targets remaining oil, complemented by injection to control reservoir pressure depletion or Low well head pressure system to produce from low pressure reservoir. The post gas cap production scenario shows that theoretically there is an opportunity to recover oil after gas cap production.
Objectives:The development of a Reservoir Rock Typing (RT) scheme for a heterogeneous and challenging reservoir is described. RT is an essential method to link capillary pressure data, conventional core analysis and logs. A valid RT scheme permits proper allocation of permeability and water saturations to reservoir grid cells resulting in accurate performance predictions allowing optimization of development options. Methods:The approach taken was to carefully select key wells with maximum data. These were usually the most recently drilled.Analysis proceeded in two directions from the logs via electrofacies analysis using Self Organizing Maps and from the capillary pressure curves.The limited number of the latter meant the results are based on the logs plus conventional core analysis (CCA) porosity and permeability data. Saturation height curves per rock type are provided by association to MICP clusters.Challenges arise when older wells have very different (typically poorer) datasets than newer wells.Logging tools have evolved over time especially those used in rock typing such as bulk density, neutron porosity and gamma ray. In this study logs span 6 decades starting from the 1960's. Techniques of Pc measurement and the quality of data have also varied over time.MICP is a technique used to derive Pc curves. A drawback is that mercury does not wet the rock and may not accurately mimic reservoir fluids at high entry pressures. Some older and less well measured curves dropped to zero at high entry pressure. Integrating air/water porous plate Pc measurements was also a challenge.The Pc curve data analysis used all measurements that passed a set of quality control checks.Results: Well defined clusters were generated by means of Self Organizing Maps (SOM) and were used to define ten electrofacies. Two of the electrofacies were very similar and were merged during the assignment of electrofacies to the MICP clusters to provide nine rock types. The rock types were compared to lithofacies determined in an associated Sedimentological study. Good correlations were found -particularly on an individual layer basis --giving good confidence on the log-core derived answers. Permeability and saturation from height were generated along the logged wells and a good match to core permeability and log saturation was obtained over most intervals. Novel Information:The most common approach to developing an RT scheme is to use a supervised training method to associate electrofacies to MICP clusters. This was attempted as a first approach but failed as cluster definition was poor due to the complexity of the rocks and limited availability of MICP data. This paper demonstrates an alternative approach that can succeed even in very heterogeneous rocks.In this paper the following terms are used to describe groupings of similar rocks, each made using different methods and assumptions:• Facies Association (FA) -based on geological examinations and methods • Electrofacies (EF) -based on electric log signatures but not yet linked to the core prope...
Objectives The objective of this paper is to calibrate porosity and permeability derived from NMR logs to core measurements and thus allow improved porosity and permeability prediction from new and historic NMR logs. Permeability, and to a lesser extent porosity, are the most important parameters in determining the potential production of a reservoir. Measuring these parameters accurately is challenging in carbonate formations due to heterogeneity and the wide variety of pore classes, such as interparticle porosity, moldic porosity, vuggy porosity, and microporosity. Traditional density-neutron and sonic tools used to measure the porosity are strongly dependent on lithology which might yield incorrect porosity measurements. NMR logs, while largely independent of matrix properties, can potentially underestimate microporosity. No wireline tool is capable of continuous permeability logging. Methods In this study, we provide an assessment of NMR measurements at laboratory and reservoir conditions to allow improved estimation of porosity and permeability. The formation under investigation is largely limestone, with negligible dolomite or clay – but has a large range of pore structures. Several samples from different rock types were selected for this study. These were investigated with computed tomography scanning, thin section analysis, and high pressure mercury injection capillary pressure (MICP) tests. NMR T1 and T2 measurements on fully formation water saturated samples were then conducted at laboratory and reservoir conditions. Finally, to define the bound and free water, and determine appropriate T2cutoff(s) for each rock type, samples were desaturated to irreducible water saturation (Swi) using a centrifuge technique, followed by NMR T1 and T2 measurements at Swi at reservoir conditions. Additionally, the laboratory NMR measurements are compared to wireline log NMR measurements at the same depths. Results Pore size distributions from NMR measurement agree well with those derived from MICP tests. The NMR measurements on desaturated samples showed that Swi and the corresponding T2cutoff vary from sample to sample. Possible controls on this will be discussed. The results from this study showed that T1 measurements confirm T2 responses: both are strongly dependent on temperature, but less dependent on pressure. Novel Information A strong 1 to 1 correlation between helium porosity, φHE and NMR porosity, φNMR was observed demonstrating that in this formation under recording of microporosity is not an issue. Based on NMR data, permeabilities were calculated using both the Coates and SDR models. It was found that the Coates model gives good agreement with permeabilities measured on core plugs by the standard laboratory techniques.
scite is a Brooklyn-based organization that helps researchers better discover and understand research articles through Smart Citations–citations that display the context of the citation and describe whether the article provides supporting or contrasting evidence. scite is used by students and researchers from around the world and is funded in part by the National Science Foundation and the National Institute on Drug Abuse of the National Institutes of Health.
hi@scite.ai
10624 S. Eastern Ave., Ste. A-614
Henderson, NV 89052, USA
Copyright © 2024 scite LLC. All rights reserved.
Made with 💙 for researchers
Part of the Research Solutions Family.