Carvalho, Ricardo de Paula (Baker Hughes, a GE company) | Barrros, Robledo Wakin (Baker Hughes, a GE company) | França, Cícero Rondinelli (Baker Hughes, a GE company) | Silva, Deylla Gomes da (Oil Service Company)
This paper describes the efficiencies of deploying the electro-mechanical pipe cutting (EMPC) tool with intelligent coiled tubing, highlighting the advantages of this tool compared to existing ballistic, chemical and other mechanical tools in terms of precision, time cost savings and HSE performance. The paper also covers the added advantages generated through the use of intelligent coiled tubing on the overall operation.
The recent introduction of intelligent coiled tubing equipment, incorporating real-time downhole tool capabilities, data communication transfer and power supply, has made possible the deployment of the electro-mechanical multiple cutting tool on coiled tubing. The emergence of this technology enables the cutting tool to perform operational applications previously unachievable in long horizontal wellbores. In the deepwater environment, there is an expectation of an increase in plug and abandonment projects. This increase will create new challenges relative to cutting and retrieval of the completion tubing. The electro-mechanical cutting tool has been proven in recent years to be an extremely reliable, efficient, and safe method to perform cutting operations in tubulars, sand screens, as well as releasing packers in high-pressure environments. The paper presents a case history detailing this methodology and the involved pre-job planning, deployment risk and management modeling, demonstrating and concluding the completeness of this solution and its reliability.
The paper shows how the combination of intelligent coiled tubing with the electro-mechanical cutting technology can render the usage of ballistic, chemical and other mechanical devices as unnecessary and outdated/inefficient.
Li, D. (Zakum Development Company ZADCO) | Alobedli, A. (Zakum Development Company ZADCO) | Selvam, B. (Zakum Development Company ZADCO) | Azoug, Y. (Zakum Development Company ZADCO) | Obeta, C. (Zakum Development Company ZADCO) | Nguyen, M. (Zakum Development Company ZADCO) | Al-Shehhi, B. H. (Zakum Development Company ZADCO)
In the current practice, ICD/ICV design parameters (e.g., number of compartments, compartment size, number of nozzles, and nozzle sizes) are optimized by a manual trial-and-error approach that requires tens to hundreds of iterations. To make the design process efficient and effective, an automated optimizer is desired. In addition, as more and more ICD/ICV wells are completed, reservoir simulation faces a challenge on how to efficiently run full field models with multiple ICD/ICV wells. This paper presents a new automated ICD/ICV design optimizer and an efficient way to run full field reservoir simulation with hundreds of ICD/ICV wells.
The new optimizer uses oil recovery efficiency as its objective function. The optimizer works on injectors and producers separately. For injectors, the optimizer adjusts the packer locations, number of nozzles, and nozzle sizes to make the injection velocity along the wellbore as uniform as possible to ensure a uniform injection front. For producers, a five step optimization process is applied. Step 1 is to generate injected fluid flow travel times in 3D from injectors to producers and all major flow "highways" are identified. Step 2, the optimizer uses fluid travel times in a producer to automatically estimate number of compartments needed and adjust the compartment boundaries (packers) to match the "highways" identified, estimate number of nozzles needed and initial nozzle sizes to maximize oil production rate. No reservoir simulation is required in steps 1 and 2. Step 3 is to run a full field reservoir simulation with all design wells to tune and achieve the final nozzle sizes. Step 4 is to QC and analyze the results of all ICD/ICV wells and select all successful candidates for the final step, i.e., step 5 reconciliation of the designs with all other drilling/completion constraints. The optimizer is fully supported by the efficient well management logic which accurately and efficiently links ICDs/ICVs with reservoir simulation. Using the well management logic removes the needs of coupling between well simulation tools (e.g., NETool) and reservoir simulation software, and then makes full field simulations efficient.
The new optimizer and well management logic have been applied and demonstrated significant values in a giant oil field in UAE. Compared to the traditional one-well-at-a-time well design, the new optimizer optimizes multiple ICD/ICV design wells at a time and results in better and faster designs with speedups in a range of several factors to an order of magnitude. The optimization is global and within the context of full field model. Running 370 ICD/ICV wells with the well management logic for a multi-million-cell reservoir simulation model only slows down the full field simulation around 10%.
Offshore reservoirs are subjected to pressure loading from the ocean tide. The resulting pressure fluctuation, notably its amplitude and phase, provides valuable information about the formation compressibility and heterogeneity. The purpose of the present study is twofold: first to propose a method for calculating tidal efficiency from harmonic analysis of regional tide stations and detrended bottomhole pressure, and second to compare the compressibility from tidal analysis to that obtained from rock mechanics measurements and material balance. This case study is on a fractured oilfield for which matrix laboratory measurements alone cannot capture the large scale formation compressibility which is driven by the .fracture distribution.
This paper will show how, in the absence of seabed pressure measurement, a synthetic diurnal tide can be simulated by interpolating the harmonic constituents of neighbouring tide stations. A new procedure combining Savitzky-Golay filter and cubic splines gave satisfactory results to filter out the tidal signal residual from the reservoir transient response. The tidal efficiency and pore pressure compressibility, computed through history for several wells, showed a clear correlation with the fracture tendancy. Also fluid effects, caused by higher water saturation in downdip wells or gas breakthrough, produce a clear signature on the tidal efficiency.
Wei, Bing (Southwest Petroleum University) | Zhang, Xiang (Southwest Petroleum University) | Wu, Runnan (Southwest Petroleum University) | Lu, Laiming (Southwest Petroleum University) | Li, Yibo (Southwest Petroleum University) | Pu, Wanfen (Southwest Petroleum University) | Jin, Fayang (Southwest Petroleum University) | Wang, Chongyang (Southwest Oil and Gas Field Company.)
CO2 based gas injection techniques for enhanced oil recovery (EOR) coupled with offsetting greenhouse gas emissions have received significant attention. In this work, a tight geological reservoir in China was focused. To further unlock the reserves after a natural depletion, the technique of SCCI was therefore suggested. The interest of this paper was to study the production response of the tight reservoir to SCCI and CO2 sequestration efficiency during this process. As a result of CO2 dissolution, the viscosity of the crude oil was gradually reduced with CO2 molar fraction and then nearly plateaued from 35 mol%. For this given reservoir, the optimal depleting pressure to implement SCCI was 20.88 MPa, which corresponded to the highest ultimate oil recovery. Moreover, the oil recovery increased linearly with CO2 slug size due to the pressurizing effect and viscosity reduction, which thus led to 11% of incremental oil recovery after a natural depletion. However, the oil production rate was found to rapidly decline with the decrease of core pressure. Due to the limited gas diffusion, the oil recovery steeply dropped with the cycle number and only 0.5% of oil was produced at the third cycle, indicating the insufficiency of SCCI to further mobilize the oil in place. During the SCCI, more than 85% of the injected CO2 species have been retained in the tight porous media.
The roles of nanoparticles in enhanced oil recovery (EOR) are typically associated with stabilization of foams and emulsions (
Conventional and non-equilibrium Molecular Dynamics (MD) techniques were applied to simulate behavior of nanoparticles and surfactant molecules on oil-water-rock interfaces in stationary and flow conditions and compute the energies of interactions between the components of the studied systems as well as interfacial tensions in them.
Moving nanoparticles were found to be effective in detachment of oil film from rock surfaces. Increased temperature and addition of surface-active agent further enhance the oil-sweeping capability of colloidal nanosuspensions.
Changes in interfacial tension as well as density profile computations showed that functionalized silica nanoparticles and related surfactant-nanoparticle compositions clearly exhibit surface active properties on oil-water interfaces that can be fine-tuned and utilized in EOR applications.
The wettability-altering potential and surfactant-transporting capability of nanoparticles are also demonstrated.
Oil-sweeping, wettability-altering, and surfactant-transporting capabilities of nanoparticles are demonstrated on the molecular level for the first time. Authors also believe that it is the first systematic numerical study of nanoparticle's and surfactant's contribution to the changes in interfacial tension on oil-water interface.
A Cathodic Protection system can provide effective corrosion control against external corrosion threats to above-ground storage tanks; be it related to tank construction materials, coating degradation over operational life span or environmental corrosion caused by tank foundation, soil etc. Traditionally, several different types of anode installation schemes were practiced for current distribution to the tank bottom. These were ‘Horizontal or vertical’ anode installation distributed around the tank periphery or angular drilled anode installation to extend the anodes toward center of the tank bottom. Deep-well anode systems with multiple anodes in a single long bore-hole at relatively remote location were also used to provide common cathodic protection system for multiple tanks in tank farm area. These conventional anode-beds were easy to install, monitor and maintained. For safety and environmental reasons in new storage tank construction, an impermeable plastic membrane is now required to be laid under the tank to contain any corrosion leak if it happens. The use of a membrane beneath the tank bottom as secondary containment and as a means of leak detection thwarts any attempt of conventional anode-bed outside the tank periphery to be effective. The anode-bed and references electrodes or other monitoring systems are therefore installed within the space available between the membrane and the tank bottom during construction of the tank, as retro-fitting of anodes during operational service life would not work because of the inaccessibility below the tank bottom. A robust design of the cathodic protection system for a tank bottom is therefore imperative to ensure intended design life.
This paper briefly discusses the changing perspectives of the cathodic protection system from conventional anode-beds to a grid system showing the detail design approach adopted and highlights the implications of miss-design based on a practical example of a newly constructed 100 meter dia crude oil storage tank with 40 years design life if relevant design considerations are not addressed.
Presence of natural fractures in reservoirs increases heterogeneity and modeling complexity while playing a significant role on well productivity and field recovery. Placing horizontal wells in naturally fractured tight carbonate reservoirs is extremely challenging due to the large variation in the natural fracture density and consequently in the formation permeability. To enhance and maintain production from such reservoirs, hydraulic stimulation is conducted to create new fractures and activate pre-existing natural fractures. However, during production/injection periods, poromechanical properties of the fractured reservoir might change with changing pressure and stress conditions. This affects ultimate recovery and results of future well placement and stimulation efforts. Changes in the properties, such as enhancement or reduction in permeability, also complicate computational modeling and performance forecasting of the reservoir. In this paper, we propose a framework to capture such flow-induced property changes in a fractured reservoir.
Our framework is based on a sequential solution of three coupled problems: (1) mechanical deformation (2) fluid flow, and (3) fracture propagation. We use the finite element method to solve the quasi-static mechanical deformation problem, the finite volume method to solve the Darcy flow problem in the matrix, and a damage mechanics approach to model propagation of pre-existing spatially distributed fractures and the ensuing evolution in flow and mechanical properties of the reservoir. We use the fixed strain scheme to couple the mechanical problem with the flow problem sequentially. The two problems are coupled to the fracture propagation problem via stresses, pressure, elastic moduli, and permeability.
The framework allows for coupled flow, deformation and damage in fractured reservoirs without the computational burden associated with an explicit fracture representation. This means we can obtain accurate predictions in realistic scenarios of production from heavily fractured and stress-sensitive reservoirs. Modeling these processes will also help in optimizing horizontal well placement decisions.
Ferrero, M. Boya (Petroleum Development Oman) | Dhahli, A. (Petroleum Development Oman) | Unal, E. (Petroleum Development Oman) | Bazalgette, L. (Petroleum Development Oman) | Wahabi, A. (Petroleum Development Oman) | Holst, M. (Petroleum Development Oman) | Doan, H. (Petroleum Development Oman)
The development of thin oil rims in carbonate reservoirs requires good understanding of structural setting, reservoir architecture and transition zone saturations. Fields that have a tectonic and/or geochemical history after initial charge are likely to challenge standard assumptions of fluid distribution, contacts and saturation-depth relationships.
This paper is a case study illustrating downflank field extension opportunities in an oil rim, related to post-charge tectonics affecting fluid distribution and contacts.
The structure of this article encompasses four different aspects: begins by explaining the geological concepts that are being postulated for downflank hydrocarbon potential, proposes the alternative methodology of concept-driven analysis for log data interpretation, explains in detail the methodology applied to existing field data for reservoir architecture and fluid fill description, summarises the outcome of the appraisal well with respect to alternative concepts.
begins by explaining the geological concepts that are being postulated for downflank hydrocarbon potential,
proposes the alternative methodology of concept-driven analysis for log data interpretation,
explains in detail the methodology applied to existing field data for reservoir architecture and fluid fill description,
summarises the outcome of the appraisal well with respect to alternative concepts.
The workflows that justified the placement of appraisal wells downflank followed the philosophy of concept-driven analysis where data is used to eliminate hypothesis rather than averaged into one a-priori assumption or average fitting equations. The placement of the pilot appraisal well (at a depth interval and location where previous models predicted water-fill) has been enabled by the identification of stratigraphic rock types, regional variability of fracture intensity and the prediction of tilted contacts. The results of an appraisal well drilled in 2017 confirm the alternative concepts proposed from concept-driven analysis of legacy log data: Flank reservoir thickness improvement due to post-deposition crestal erosion of best facies. Fracture density reduction towards the northern flank of the dome structure. Tilted oil contacts deepening towards the flank and related to paleo-charge. Relatively dry oil production from deeper depth intervals with low oil saturation due to transition zone water mobility.
Flank reservoir thickness improvement due to post-deposition crestal erosion of best facies.
Fracture density reduction towards the northern flank of the dome structure.
Tilted oil contacts deepening towards the flank and related to paleo-charge.
Relatively dry oil production from deeper depth intervals with low oil saturation due to transition zone water mobility.
The drive mechanism and development options for the field should be investigated further.
More and more cement compositions used for oil and gas wells, such as resilient cement with post expansion additives, are designed to obtain elastic and strength properties as well as pre-stresses in the cement sheath that allow the cement sheath to resist tensile or shear stresses induced by pressure and thermal loads emanating from the well during its full life cycle.
The computation of stress changes induced by well loads once the cement is hardened is straightforward. Those stresses will depend on geometrical parameters such as casing and hole sizes on one side and on elastic properties of casing, cement and formation on the other side. The difficulty stems from the need to compute the pre-stress in the cement sheath which is the result of complex hydraulic, chemical, thermal and mechanical interactions during hydration. Another difficulty is to measure the evolution of relevant hydro-thermo-mechanical (HTM) parameters that affect the transition from hydrostatic pressure after placement to stress with shear components after hardening.
In the recent years, Total has developed both modeling and laboratory capabilities that allow to characterize the HTM behavior of cement under in-situ pressure and temperature conditions and to use the measured parameters to analyze the mechanical integrity of cement sheath from placement on. Those tools are now routinely used to determine the best suited ranges of mechanical properties on one side and to QC and adjust cement systems proposed by service companies. This approach allowed achieving successful cementation of wells in harsh environment such as HP-HT wells.
The development of the software and laboratory facilities with internal resources proved beneficial from many perspectives. A great advantage is to be able to know how the various parameters associated with different cement compositions are affecting the cement integrity under specific down hole conditions. More importantly, it allows Total as an operating company to perform sound validation through confrontation to real field cases.
The aim of this paper is to present the fundamental concepts used in the Total's proprietary cement integrity model called T-CemInt and to describe the associated parameters and the ways of measuring them in the laboratory. Also, the paper will show a real case study that included lab tests, modeling and post cement sheath assessment with standard logging tools.
Buildings that are manned and/or housing critical equipment are ideally conceived to be sited at safe distance away from potential explosion sources of the gas processing facilities. However it is not always possible to maintain the required stand-off distance due to several layout/operational constraints in brownfield projects and hence plant buildings are invariably subjected to the blast effects. The paper discusses challenges confronted and best practices followed in GASCO for blast protection of plant buildings.
Quantitative Risk Assessment study forms the basis for blast considerations on the building, wherein potential Vapor Cloud Explosion scenarios are identified and blast overpressure are quantified in the form of contours on the plot. Buildings located within the blast contours and are manned/housing critical equipments are classified as blast-resistant to ensure safety to occupants and facilitate safe shutdown of process units during explosion. Building performance requirement defining acceptable level of damage is determined based on criticality of the facility/expected occupancy (control room, FAR, etc.). Structural system/material appropriate to blast intensity is chosen and a dynamic or equivalent static analysis is performed.
Blast resistant design followed for buildings in GASCO plants incorporates a practical approach blending past experiences with best known practices in the industry. Building Blast Design Requirements (BDR) data sheet is introduced at early stages of the project and specific requirements such as blast load parameters, building configuration, structural system & foundation type, building response range and other special requirements are developed and firmed up before the commencement of detailed design.
Single-storied regular shaped buildings with no windows or minimum windows with special features are preferred. Elevated ground floor is permitted in certain cases such as Substation to create cable vault. However this presents unique challenges in establishing blast pressure distribution due to lack of guidelines for such set-up, which is overcome by own novel solutions.
For low blast loads, simplified static approach is adopted for structural analysis, while dynamic analysis with SDOF approach yields economical design for medium to high blast loads. In specific cases where SDOF idealization is inappropriate (as in multi storied building), a MDOF non-linear FE analysis is carried out.
RC framed structure with reinforced masonry walls, or steel structure is adequate for low blast, while RC shear wall structure is found most effective to sustain moderate to high blast.
The paper presents best practices and unique approach followed in GASCO for such design amid growing challenges of achieving high performance at low cost. These requirements are common for similar expansion projects and hence can be adopted across the industry.