Whole level of the erosion and the resistance of rocks which were composed closured have been studied, besides, the impact of temperature and laser irradiation for more investigation about this issue has been involved before all. This subject more reveals the matter which laser absorption on the laboratory scale using laser to what extent can cause the augment of the relative permeability and secondary porosity of reservoir rock, that of the vertical and horizontal useful connectivity and eventually that of the positive transferability.
This research has been carried out in the form of case study on one of Iranian south west formations in north east of Behbahan city in Iran, either the rate or generation of forming the subtle and large fractures has been studied by considering and preparing this section from rocks of stratified sequence of the laboratory area before and after the laser irradiation operation and various analyzer by the means of Spectrophotometer and advanced electron microscope. It should be noted that during the erosion and ablation in the laser drilling operation in the experimental rocks of considered field, given the capability of the field, the formation and field lithology we observed the creation of fractures at the level of micro and nano simultaneously whose vacant spaces were positive, and reservoir and some others were neutral, this fractures can be created by the rate of crude oil absorption. The main purpose of this study is to advance the operations towards the higher technology in order to the better efficiency in the field of the well completion to be gained improving the rate of oil production by the introduction of this modern method of improving and fracturing reservoir which uses certain specialized parameters and indicators, and, finally, the certain method that might be a better way to use laser irradiation on our chosen formation of Iran.
Acharya, Mihir Narayan (Kuwait Oil Company) | Kabir, Mir Md Rezaul (Kuwait Oil Company) | Al-Ajmi, Saad Abdulrahman Hassan (Kuwait Oil Company) | Pradhan, San Prasad (Kuwait Oil Company) | Dashti, Qasem M. (Kuwait Oil Company) | Al-anzi, Ealian H.D. (Kuwait Oil Company) | Chakravorty, Sandeep (Schlumberger)
The deep, sub-salt reservoir complex is tiered with fractured tight carbonate at bottom and top, with the two sub-units of "upper unconventional kerogen?? and "lower inter-bedded kerogen-carbonate?? in the middle. This depositional setting is challenging for horizontal well placement where the thicknesses of respective sub-units are about 50 and 30 feet with varying geomechanical and petrophysical properties. Additionally, this complexity poses limitations in completions and effective stimulation of the Kimmeridgian-Oxfordian reservoirs in several gas fields at development stage in Kuwait.
A horizontal well is placed in the lower sub-unit of the laminated complex of unconventional kerogen and fractured carbonate reservoir as a Maximum Reservoir Contact (MRC) type well. A pilot mother-bore was drilled and logged to identify the lithological properties across the entire vertical domain - facilitates the optimization of horizontal drain-hole placement within the targeted reservoir units.
No wellbore stability issues in drilling were predicted based on the geomechanical understanding where core-calibrated logs from offset vertical wells were considered. However, this modeling method did not have the functionality to integrate the impact of drawdown on the laminated formation which became unstable and collapsed during the short open-hole drill-stem test (DST) plugging the tubing prior to the final completions. An alternative "book-shelf?? geomechanical model was considered at pre-drill stage for predicting the wellbore stability. Once the drilling was completed, the time-lapsed multi-arm caliper indicated the validity of the alternative methodology in predicting the unstable stack of laminations in kerogen-rich strata.
The paper discusses an optimization methodology to enhance the understanding of static and dynamic geomechanical stability through the use of BHI data. Objective of the proposed method is to help improve the effectiveness of completions where wellbore stability due to geomechanical complexity in stacked-pay reservoirs is a primary wellbore challenge in deploying the completions and executing a subsequent stimulation and testing campaign.
Low matrix permeability and significant damage mechanisms are the main signatures of tight gas reservoirs. During drilling and fracturing of tight formations, the wellbore liquid invades the tight formation, increases liquid saturation around wellbore and eventually reduces permeability at near wellbore. The liquid invasion damage is mainly controlled by capillary pressure and relative permeability curves.
Water blocking and phase trapping damage is one of the main concerns in use of water based drilling fluid in tight gas reservoirs, since due to high critical water saturation, relative permeability effects and strong capillary pressure, tight formations are sensitive to water invasion damage. Therefore, use of oil based mud may be preferred in drilling or fracturing of tight formation. However invasion of oil filtrate into tight formations may result in introduction of an immiscible liquid hydrocarbon drilling or completion fluid around wellbore, causing entrapment of an additional third phase in the porous media that would exacerbate formation damage effects.
This study focuses on phase trapping damage caused by liquid invasion using water-based drilling fluid in comparison with use of oil-based drilling fluid in water sensitive tight gas sand reservoirs. Reservoir simulation approach is used to study the effect of relative permeability curves on phase trap damage, and results of laboratory experiments core flooding tests in a West Australian tight gas reservoir are shown in which the effect of water injection and oil injection on the damage of core permeability are studied. The results highlights benefits of using oil-based fluids in drilling and fracturing of tight gas reservoirs in term of reducing skin factor and improving well productivity.
Tight gas reservoirs normally have production problems due to very low matrix permeability and different damage mechanisms during well drilling, completion, stimulation and production (Dusseault, 1993). The low permeability gas reservoirs can be subject to different damage mechanisms such as mechanical damage to formation rock, plugging of natural fractures by invasion of mud solid particles, permeability reduction around wellbore as a result of filtrate invasion, clay swelling, liquid phase trapping, etc (Holditch, 1979).
In general, for tight sand gas reservoirs, average pore throat radius might be very small and therefore it may create tremendous amounts of capillary forces. Capillary forces cause the spontaneous imbibition of a wetting liquid (in this case water) in the porous medium in the absence of external forces such as a hydraulic gradient (Bennion and Brent, 2005). This causes significantly high critical water saturation (Bennion et al., 2006). Two forces drive capillary flow (Adamson and Gast, 1997). The first is the reduction in the surface free energy by the wetting of the hydrophilic surface (wettability). In hydraulic fracturing, water in the fracturing fluid wets the surface of the pores in the rock, resulting in a decrease in the surface free energy of the pores. The other force that drives capillary flow is the capillary pressure.
Tight gas reservoirs might be different in term of initial water saturation (Swi) compared with critical water saturation (Swc), depending on the geological time of gas migration to the reservoir. Initial water saturation might be normal, or in some cases sub-normal (Swi less than Swc) due to water phase vaporization into the gas phase (Bennion and Thomas, 1996). The initial water saturation might also be more than Swc if the hydrocarbon trap is created during or after the gas migration time. A sub-normal initial water saturation in tight gas reservoirs can provide higher relative permeability for the gas phase (effective permeability close to absolute permeability), and therefore relatively higher well productivity (Bennion and Brent, 2005).
Lost circulation caused by low fracture gradients is the cause of many drilling related problems. Typically the operational practice when lost circulation occurs is to add loss circulation materials (LCM) to stop mud from flowing into the formations.
To improve the treatment for lost circulation caused by low fracture gradients, especially designed materials in mud system are used to seal the induced fractures around the wellbore. This operation is in the literature referred to as wellbore strengthening that has been found to be a very effective in cutting Non-Productive Time (NPT) when drilling deep offshore wells. Size, type and geometry of sealing materials are debating issues when different techniques are applied. Also the phenomenon is not truly understood when these techniques applied in different sedimentary basins.
This paper presents development and simulation results of a three-dimensional Finite-Element Model (FEM) for investigating wellbore strengthening mechanism. This study also describes a procedure for designing Particle Size Distribution (PSD) in field applications. To better understand the numerical results, the paper also reviews the connection between Leak of Tests (LOTs) and wellbore hoop stress and how these LOTs can mislead in fracture gradient determination.
A comprehensive field database was collected from different sedimentary basins for this study. Results demonstrate that the maximum attainable wellbore pressure achieved by wellbore strengthening is strongly controlled by stress anisotropy. Results also show that Particle Size Distribution (PSD) of wellbore strengthening should be designed in order to seal the fractures close to the mouth and at fracture tip. This will result both in maximizing hoop stress restoration and tip-screening effects. In addition this model is able to show the exact fracture geometry formed around the wellbore that will help to optimize the sealing materials design in wellbore strengthening pills. To support numerical modeling results, near wellbore fracture lab experiments on Sandstone and Dolomite samples were also presented. Laboratory experiments results reveal importance of rock permeability, tensile strength and fluid leak-off in wellbore strengthening applications.
Narrow pore-fracture window in deep and ultra-deep offshore environments, highly deviated wellbores and depleted formations is the most prominent drilling challenge today. Lost circulation and high non-productive time due to the tight window is the major motivation for widening operational window and using wellbore strengthening techniques. Wellbore strengthening can be defined as "a set of techniques used to efficiently plug and seal induced fractures while drilling to deliberately enhance the fracture gradient and widen the operational window??. This technology has the potential to mitigate the lost circulation problem, and improve wellbore integrity to avoid well control disasters. In addition, it might reduce the number of casing strings required to drill deep water wells.
Previous joint industry projects (DEA-13 and GPRI) conducted experiments to investigate lost circulation. The main finding from these projects was the ability to increase fracture reopening pressure by using specific type and size of materials in the drilling fluid system (Morita et al., 1996a, b, and Dudley, 2001). Investigating the physical mechanism that enhances the fracture gradient was not truly feasible using these experiments. Therefore, a clear understanding regarding the effect of material properties (size, type and strength) of the actual sealing mechanism was never achieved but spurred continuous investigations on how drilling fluids can improve the fracture gradient. Table 1 summarizes the wellbore strengthening methodologies, whereby some of them differentiate in the mechanism involved, material type and strength to be used plus the necessity for tip isolation.
Exploration and production from unconventional shale resources has increased significantly in the past several years due to the success of combining horizontal drilling and hydraulic fracturing technologies in a manner that allows natural gas and/or oil to be released from relatively impermeable shale formations. The rapid increase in shale development has raised the concern of landowners and the public that the use of these techniques could adversely impact the groundwater resources in and around the development. In general, there is a lack of real data documenting pre-drill and post-drill conditions that could be used to truly evaluate the impacts of shale development. Using a technically sound strategy to collect data is important in an effort to document baseline environmental and, in particular, groundwater conditions prior to exploration so that post drilling conditions can be evaluated when necessary. The collection of scientifically defensible data for operators involved in the development of a shale play improves stakeholder engagement, protects operators from potential environmental degradation claims, and allows for science-based regulation that truly protects the resources. Collecting a representative set of samples from groundwater supply wells within a defined radius of a well pad prior to drilling activities provides the operator with information that documents pre-drilling groundwater conditions. Performing this type of baseline sampling within a well-designed, scientifically and legally defensible program can help the operator manage and mitigate corporate risk. The public concern over impacts to groundwater must be taken seriously, and adhering to a well designed program that produces science-based results will increase public confidence in the industry's operating practices. This paper presents baseline groundwater sampling program rationale and design based upon existing regulations and experience gained in the United States shale exploration regions.
Deepwater corals (Lophelia) were identified in the vicinity of the location of the exploration well Pumbaa (NOCS 6407/12-2) on the Norwegian Continental Shelf where a drilling operation was carried out by the GDF SUEZ E&P Norge AS (GDF SUEZ). Det Norske Veritas AS has on behalf of GDF SUEZ conducted an environmental monitoring of drilling activities at Pumbaa (NOCS 6407/12-2).
Because of registrations of deep water corals (Lophelia) in the Pumbaa area, and due to specific requirements - a relatively comprehensive monitoring of the drilling activities was carried out. Only the drill cuttings from the top hole sections were discharged at the sea floorThe generated cuttings and used mud from deeper well sections were not discharged to sea. In order to increase the distance to the nearest corals from the discharge point, a Cuttings Transport System (CTS) was used to transport discharges from the top hole sections and all discharges were at 300m distance NNW (310 degrees) of well location.
The main objective of the monitoring was to assess effects from the drilling activities on the corals south (and nearest) of the drilling location. The monitoring program included measurements of current, turbidity and sedimentation, as well as sampling of sediments from the seafloor. Sediment samples from the seafloor and sedimentation traps were analyzed for heavy metals and physical parameters. Coral structures were visually inspected before, during and after drilling operations.
Gioia, Giusi (Eni Div. E&P) | Cislaghi, Raffaella (GSA) | Mariani, Maurizio (AECOM) | Germiniani, Erika (Politecnico di Milano) | Zampori, Luca (Polimi) | Dotelli, Giovanni (Eni E&P) | Mastrapasqua, Alessandra (Eni S.P.A.) | Sandri, Simonetta (Politecnico di Milano) | Stampino, Paolo (AECOM) | Battaglia, Alessandro
This work is focused on identifying a scenario for the reuse of drilling cuttings and contaminated sands coming from Block 403A, in Algeria (ROM and ZEA fields operated by GSA), which are typical oil exploration and production wastes (e&p waste). The selected treatment was the Solidification/Stabilization (S/S) process using Ordinary Portland Cement as binder matrix and addressed the stabilization of Petroleum Hydrocarbon contaminants. The leaching of organic contaminants from stabilized waste product treated with Portland cement has been reported in some publications. Leaching test results have shown relatively high release of Polycyclic Aromatic Hydrocarbon  and methanol 2-chloroaniline  and .
The mix design consisted in different concrete monoliths prepared to simulate the forms for the future waste reuse made of different ratios of Ordinary Portland Cement (OPC), waste -drilling cuttings (DC) or contaminated sands (CS), superplasticizer (SP) and fly ash (FA). A testing framework was applied to assess the mineralogical composition, microstructural features, leaching behavior as well as the mechanical and physical properties of the stabilized waste.
A mineralogical characterization of the cement pastes highlighted the presence of typical hydration products, along with the phase of anhydrous Portland Cement, which are probably related to the detrimental effects on the hydration process caused by contaminants. Microscopic observations suggested that the addition of fly ash should not result in performance improvement and that the cement pastes prepared using a lesser amount of water due to the addition of a superplasticizer exhibited the lowest porosity which strongly influence concrete performance. Organic contaminants are immobilized through a physical entrapment within the binder matrix and sorption onto the surface of binder hydration products given that no contaminants were measured into the eluates. Compressive strength grades measured on pastes prepared with superplasticizer are higher than the ones prepared without the water reducing admixture. Additional criteria to select the best recipe are related to the working applicability, sustainability and optimization of the production process at full scale.
This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 152339, "Assessment of an Unusual European Shale-Gas Play: The Cambro- Ordovician Alum Shale, Southern Sweden," by Wilfred Pool, Mark Geluk, Janneke Abels, and Graham Tiley, Shell International E&P, and Erdem Idiz and Elise Leenaarts, Shell Global Solutions International, prepared for the 2012 SPE/EAGE European Unconventional Resources Conference and Exhibition, Vienna, Austria, 20-22 March. The paper has not been peer reviewed.