Natural gas hydrate formation is a costly and challenging problem for the oil and gas industry. Prediction of hydrates have been carried out through rigorous and laborious solving of mathematical equations called equations of state (EOS) which give accurate results but require appropriate setup and time. Few examples of such equations of state currently used by industry benchmarked software tools include Peng-Robinson (PR), Cubic-Plus-Association (CPA), Soave-Redlich-Kwong (SRK) etc. which more or less provide us with an accurate hydrate stability curve i.e. a pressure-temperature profile for a given composition, which allows us to keep the pressures and temperatures (operating conditions) out of the hydrate stability zone.
Hydrate stability curves are a function of the composition of the fluid (gas) being produced. Compositional changes in the percentage of C1 to C7+ components of gas, would not only affect the specific gravity, but would also change the hydrate stability curve of the gas significantly.
Previous studies have been aimed at finding a quick and precise prediction method for hydrate formation, so as to make swift arrangements to counter any chance of flow assurance issue. Different empirical correlations have been developed on the basis of the composition of the gas being produced that take into consideration the pressure and predict the temperature of hydrate formation. Multiple data points, i.e. fluid compositions from different areas/fields are considered and correlations have been developed to fit the hydrate stability zones of these data points which were found through a more accurate equation of state. As the initial data sets for each correlation are different, the possibility of any two correlations giving the correct and same prediction is very low.
This paper gives an insight into how different empirical correlations like Hammershmidt, Motiee, Makogon, Towler and Mokhtab etc., that have already been derived can be used with better accuracy for a set of different fluid compositions and specific gravities. A sensitivity analysis is done on the performance of each correlation against the accurate hydrate curves found out through the software tool, using different available equations of state. The data points picked here are random and were not included in any data sets adopted for derivation of the correlation.
Furthermore, the mimicked hydrate curve from this new method is cast against the software simulated hydrate curve for a flow assurance steady state simulation study with two deepwater gas wells with different gas compositions. The results of the study suggest that the use of the imitated hydrate curve through analytical approach works well in predicting the hydrate stability zone. It would also not require any software proficiency, would give quick results and would cost a fraction compared to the state of the art simulators.
Yang, Zhaopeng (PetroChina Research Institute of Petroleum Exploration&Development) | Li, Xingmin (PetroChina Research Institute of Petroleum Exploration&Development) | Chen, Heping (PetroChina Research Institute of Petroleum Exploration&Development) | Ramachandran, Hariharan (The University of Texas at Austin, Hildebrand Department of Petroleum and Geosystems Engineering) | Shen, Yang (PetroChina Research Institute of Petroleum Exploration&Development) | Yang, Heng (China National Oil and Gas Exploration and Development Corporation) | Shen, Zhijun (China National Oil and Gas Exploration and Development Corporation) | Nong, Gong (China National Oil and Gas Exploration and Development Corporation)
The block M as a foamy extra-heavy oil field in the Carabobo Area, the eastern Orinoco Belt, has been exploited by foamy oil cold production utilizing horizontal wells. The early producing area has been put into production about 10 years, existing problems of productivity declining and produced gas-oil ratio rising. Therefore, the development optimization for the early producing area should be conducted in order to obtain the more profitable oil recovery. A typical foamy oil reservoir simulation model using 5 components was created to understand the remaining oil distribution features. Based on above understandings, technical strategies were proposed for infilling well deployment in the early producing area. Results show that the gravity drainage and gravity differentiation of oil and gas during the cold production of foamy extra-heavy oil from horizontal wells by foam flooding are the main mechanisms for formation of remaining oil. And the influence factors of remaining oil distribution include horizontal well spacing, reservoir thickness, reservoir heterogeneity, interlayer distribution and reservoir rhythm. Thus tor foamy extra-heavy oil CHOP process, the enriched remaining oil area is the place between two adjacent horizontal wells with well spacing of 600m. Therefore, well infilling is an effective measure improving oil recovery factor of cold production, and the well infilling should be implemented as soon as possible to obtain better performance of cold production.
A novel discrete fracture model (DFM) approximation is presented and coupled with the control-volume distributed multi-point flux approximation (CVD-MPFA) formulation. The reduced-dimensional discrete discontinuous pressure model for intersecting fractures is extended to two-phase flow, including gravity and discontinuous capillary pressure. A novel higher resolution hybrid upwind method provides improved flow resolution on unstructured grids.
Novel discontinuous fracture models together with appropriate interface conditions, essential for application to cases involving continuous and discontinuous capillary pressure, and for fractures with permeability barrier effects are presented. The CVD-MPFA based discontinuous DFM models are coupled with higher resolution methods on unstructured grids, including an extended higher resolution hybrid upwind method for gravity driven flow and a novel higher resolution capillary flux approximation. A special DFM approximation is presented for fracture intersection cells located in flow fields where viscous and gravity forces interact.
Performance comparisons are presented for tracer and two-phase flow and fracture problems involving discontinuous capillary pressure and gravity on unstructured meshes. The results demonstrate the importance of the discontinuous DFM model to resolve flow problems including oil trapping in fractures. In addition comparison between the standard lower order method and the higher resolution hybrid upwind scheme shows that the higher resolution method yields significantly improved flow resolution in gravity driven flow fields.
A novel DFM approximation is presented and coupled with the CVD-MPFA formulation on unstructured grids. The method includes a discontinuous discrete fracture model with appropriate interface conditions for application to discontinuous capillary pressure fields, and a new method for treatment of intersecting fractures is also introduced for viscous-gravity driven flow. The method is also coupled with a higher resolution hybrid upwind scheme which yields improved flow resolution.
Shale formations exhibit multi-scale geological features such as nanopores in formation matrix and fractures at multiple length scales. Accurate prediction of relative permeability and capillary pressure are vital in numerical simulations of shale reservoirs. The multi-scale geological features of shale formations present great challenges for traditional experimental approach. Compared to nanopores in formation matrix, fractures, especially connected fractures, have much more significant impact on multiphase flows. Traditional flow models like Darcy's law are not valid for modeling fluid flow in fracture space nor in nanopores. In this work, we apply multiphase lattice Boltzmann simulation for unsteady-state waterflooding process in highly fractured samples to study the effects of fracture connectivity, wetting preference, and gravitional forces.
The increasing number of foiling yachts in offshore and inshore races has driven engineers and researchers to significantly improve the current modelling methods to face new design challenges such as flight analysis and control (Heppel, 2015). Following the publication of the AC75 Class Rules for the 36th America's Cup (RNZYS, 2018) and since the brand new Open 60 Class yachts are all equipped with hydrofoils, the presented study will propose a system-based modelling coupled with a simplified FSI (fluid-structure interaction) method that leads to better understand the dynamic behavior of monohulls with deformable hydrofoils.
The aim of the presented paper is to establish an innovative approach to assess appendage behavior in a dynamic VPP (velocity prediction program). For that purpose, dynamic computations are based on a 6DOF mathematical model derived from the general non-linear maneuvering equations (Horel, 2016). The force model is expressed as the superposition of 7 major force components expressed at the center of gravity of the yacht: gravity, hydrostatic, maneuvering, damping, propulsion (wind), control (rudders, daggerboard, foils …) and wave (Froude-Krylov and diffraction phenomenon).
As test cases, course keeping simulations are performed on an Open 60 yacht with control loops to simulate the wing trimmer, helmsman and foil trimmer when finding the optimal foil settings is needed. In first hand, IMOCA’s polar diagrams are used as reference.
In calm water and in waves, the influence of foil’s shapes (foil with shaft pointing downward and tip pointing upward, foil with shaft pointing upward and tip pointing downward) and stiffness (non-deformable, realistic, flexible) on the global behavior of the yacht is presented.
The advantages of measuring gravity in the borehole environment have been well established in the literature and through first-generation instruments. These measurements can be very effective for directly imaging mass distributions at-depth in the subsurface and at large-distances from well bores. To date, a breakthrough has been limited by the sensor form factor (size) and measurement stabilization. Newly emerging MEMS three-axis microgravity technology, deployable by wireline, is showing the potential for a host of applications and capable of realizing the long-coveted advantages. For reservoir surveillance, a primary application is to perform more pro-active, frequent flood front monitoring. With its large volume of investigation, the proposed three-axis borehole gravity measurements would complement as well as fill the existing gap between traditional methods such as Pulsed Neutron and 4D seismic. Further applications extend to saturation monitoring, by-passed pay, and thin-bed identification.
In conjunction with a collaborative program to develop a three-axis gravity sensor that is now being incorporated into a 54-mm diameter wireline tool with a targeted sensitivity ≈5 μGal (microGal), we have carried out extensive numerical studies to understand the signal strengths in such measurements produced by the dynamic processes in different types of reservoirs, and demonstrate the capabilities and limitations of borehole gravity and its potential use within a revised reservoir surveillance plan.
We show examples of forward modelling data from reservoirs with varying fluid displacement mechanisms. Reservoir porosity and saturation data are used to model the predicted three-component (i.e., vector) gravity anomaly (gz, gx, and gy) responses along the wellbore in a variety of wells as the fluid-water front progresses through the field. The modelling included both producing wells and injector wells. The paper will present a description of a forward modeling workflow, simulation studies based on real reservoir data, and the validating measurements.
The paper examines the results of the forward modelling and compares the results with the sensitivity of the new three-axis borehole gravity sensor. The results will show that a wireline deployed three-axis gravity tool with a targeted noise floor of ≈5 μGal will provide additional important surveillance to constrain reservoir models as well as provide vital information to help reduce uncertainty when actively managing waterfront movement (sweep) and secondary recovery and detecting early breakthrough of water; and for monitoring and adjusting strategy when producing through reservoir depressurization. The described workflow is seen as very important for any future survey planning to understand the time-lapse gravity signal and the feasibility of time-lapse gravity surveillance under different reservoir conditions.
A three-axis borehole gravity tool with a form factor enabling it to be deployed through cased hole and into deviated and horizontal wells is completely novel and has not been presented previously. A workflow that understands survey feasibility and optimal survey-time intervals is novel. A systematic and comparative study of three-axis borehole gravity responses through modelling of a reservoir is novel and has limited previous work.
Through Tubing Mechanical Shut off Process using electric line has been an economical and successful way to isolate undesired perforated intervals in cased whole completions. During the late 1980s & early 1990s the technology became more reliable so the oil & gas industry began to put more trust in eline capabilities for the through tubing shut-offs.
Many of offshore operating companies including Gulf Of Suez Petroleum Company "GUPCO" adopted the technique in order to minimize the number of rig work overs and accelerate add rate activities using rigless units. TTBP has proved very reliable in most of the cases however; the success rate has been debatable for highly deviated wells with high-pressure differential across the plug.
Eline applications normally struggle at deviations > 60°, because of losing the gravity force driving the tools downward, limitations of tool string length due to dogleg in the angle build up sections. Several through tubing options are now available to overcome these challenges, for example coiled tubing, which requires rig assist for offshore sattelites application, & eline tractoring, which adds more cost to eline job and depends on local availability in the area of operation. TT mechanical shut offs face some challenges more than ability to deploy tools to required depth. Several types of through tubing cement dump bailers are available in the market; however not many jobs were performed in deviations > 70°, there is always a debate about capability of bailer to dump all cement on depth at such deviation where gravity force is minimal. In addition, the effect of cement slumping in higher deviations is another challenge for building a good cement sheeth that guarantees good sheer bond strength and able to withstand required pressure differential.
A Challenging example was an offshore horizontal well where the primary target is required to be isolated and the objective is to test a new reservoir in the field which was not tested before in the area. Due to uncertainity in productivity, saturation & fluid type "Oil or gas" of the new characterized reservoir. The operations was intended to be at the minimum possible cost in order to keep the business risk at the lowest level. The target perforation interval was located in the build section of the horizontal well where deviation angle is 74-76 degrees.
The existing perforations were flooded out and it was necessary to isolate prior to test of the target reservoir. Isolation using through tubing bridge plug on eline was assessed and different operation risks were evaluated, conveyence to the target depth without an eline tractor was assessed in the planning phase using a tension model. Slickline operation was modified to confirm the validity of the model and we successfully reached the target depth using slickline. During the planning phase, we considered many precautions to guarantee job success.
A successful mechanical shut off job in a deviation of 74-76 degree was confirmed by positive test to the plug and the successful production from the well that produced more than 10 MMSCFD & 300 Barrels of condensate per day.
Shallow drilling losses are a significant problem in the Permian basin because of the presence of subsurface karst features. Karst weakens the soluble rock producing voids and caves systems that result in drilling losses. An operator drilling in Culberson County, Texas recently experienced total losses drilling four surface holes in a pair of neighboring pads located in bordering leases. Drilling into caves negatively affected operations by reducing the drilled footage per day, increasing fluid and cementing costs, and increasing the difficulty in performing satisfactory cementing jobs to cover the water table.
This paper will describe the issues faced drilling with losses and explain how to manage the risk of losses by improving surface well placement with airborne gravity full tensor gradiometry (FTG) to map subsurface hazards.
Airborne gravity FTG measures the directional components of the gravity field. Multiple simultaneously acquired tensor components allow identification of anomalies associated with subsurface voids. For this project, a Basler BT67 aircraft acquired data over the targeted expanse with line spacing of 328 ft. The aerial survey took place over 3 days in July 2017.
Feasibility modeling using Castile formation cave systems reveals detectability of single caves larger than 10 m diameter with FTG, however networks of smaller caves are also detectable. Polygons created from analysis of negative vertical gravity tensor (Tzz) anomalies separate the cave systems into tiered risk areas.
Initial analysis reveals risk at both pads where losses occurred. Extending the analysis to the entire survey, the drilling events in the drilled offset wells match with the risk interpreted for karst. FTG data and subsequent interpretation offer strong correlation to known shallow hazards and cave systems, making it a useful tool for risk assessment. It recommended to locate future drill pads in the identified moderate risk areas and that any new wells be located away from elevated risk areas.
This is the first application of FTG to classify drilling risk of karst features in the Permian basin. The FTG hazard map improves operational integrity of surface location selection and is a complement to surface topography and geology considerations. The FTG data and analysis also holds promise for fault mapping and for water drilling efforts.
While many methods of computing gas pressure in a flowing environment are available, what is needed in the case of gas lift is the static annulus pressure at depth. Historically, the method of using average temperature and pressure to compute compressibility factors and assuming linear well-temperature gradients made gas lift design relatively simple. The small errors were tolerable and within the normal design safety margins of operating systems with surface pressures of less than 1,500 psi. When surface injection pressures exceed 1,500 psi, calculations become more important. Computers are now used to calculate downhole annulus pressure, and the designer must trust the number that appears on the computer screen. That trust may not be warranted, depending on the method of calculation. The small errors that creep into computer calculations increase linearly as surface injection pressure increases. Additionally, the choice of which correlation to use to model the critical properties of the gas and which compressibility factor correlation to use also affect the accuracy of the calculation.
Post hydraulic fracture diagnostics often leads to an estimation of effective fracture lengths that are substantially shorter that the created length. (