If least-squares linear regression is used to compute N in Step 5, an equation analogous to Eq. 17 is used (where Eow is substituted for Eowf). This solution method is iterative because the material-balance error must be minimized. This calculation is carried out with a trial-and-error method or a minimization algorithm. Least-squares linear regression and minimization algorithms have become standard features in commercial spreadsheets.
In this paper, we present for the first time, a classification system for naturally-occurring gas hydrate deposits existing in the permafrost and marine environment. This classification is relatively simple but highlights the salient features of a gas hydrate deposit which are important for their exploration and production such as location, porosity system, gas origin and migration path. We then show how this classification can be used to describe eight well-studied gas hydrate deposits in permafrost and marine environment. Potential implications of this classification are also discussed.
Kholy, Sherif M. (Advantek Waste Management Services) | Mohamed, Ibrahim M. (Advantek Waste Management Services) | Loloi, Mehdi (Advantek Waste Management Services) | Abou-Sayed, Omar (Advantek Waste Management Services) | Abou-Sayed, Ahmed (Advantek Waste Management Services)
During hydraulic-fracturing operations, conventional pressure-falloff analyses (G-function, square root of time, and other diagnostic plots) are the main methods for estimating fracture-closure pressure. However, there are situations when it is not practical to determine the fracture-closure pressure using these analyses. These conditions occur when closure time is long, such as in mini-fracture tests in very tight formations, or in slurry-waste-injection applications where the injected waste forms impermeable filter cake on the fracture faces that delays fracture closure because of slower liquid leakoff into the formation. In these situations, applying the conventional analyses could require several days of well shut-in to collect enough pressure-falloff data during which the fracture closure can be detected. The objective of the present study is to attempt to correlate the fracture-closure pressure to the early-time falloff data using the field-measured instantaneous shut-in pressure (ISIP) and the petrophysical/mechanical properties of the injection formation.
A study of the injection-pressure history of many injection wells with multiple hydraulic fractures in a variety of rock lithologies shows a relationship between the fracture-closure pressure and the ISIP. An empirical equation is proposed in this study to calculate the fracture-closure pressure as a function of the ISIP and the injection-formation rock properties. Such rock properties include formation permeability, formation porosity, initial pore pressure, overburden stress, formation Poisson’s ratio, and Young’s modulus. The empirical equation was developed using data obtained from geomechanical models and the core analysis of a wide range of injection horizons with different lithology types of sandstone, carbonate, and tight sandstone.
The empirical equation was validated using different case studies by comparing the measured fracture-closure-pressure values with those predicted by using the developed empirical equation. In all cases, the new method predicted the fracture-closure pressure with a relative error of less than 6%.
The new empirical equation predicts the fracture-closure pressure using a single point of falloff-pressure data, the ISIP, without the need to conduct a conventional fracture-closure analysis. This allows the operator to avoid having to collect pressure data between shut-in and the time when the actual fracture closure occurs, which can take several days in highly damaged and/or very tight formations. Moreover, in operations with multiple-batch injection events into the same interval/perforations, as is often the case in cuttings/slurry-injection operations, the trends in closure-pressure evolution can be tracked even if the fracture is never allowed to close.
Multi-Zone, Single-Trip (MZST) completions have significantly reduced the time to complete deep wells with long intervals and have been successfully used in Lower Tertiary formations in deep-water Gulf of Mexico (GOM) projects. MZST completion can be used to create the interface with the reservoir and to deliver stimulation treatments typically limited to up to single-digit zones. Additionally, the minimum spacing allowed by standard MZST completions limits the treated zone length.
The Lower Tertiary formations encounter high-laminated pay zones, often hydraulically isolated, and with pressure variations across the small spacing length. Therefore, a treatment covering several compartments results in uneven treatment distribution across long intervals. These single-trip systems require a high proppant amount and pressure to complete the sizeable frac-pack jobs required in Lower Tertiary formations. Using ball-activated fracturing sleeves and dedicated fracturing ports, these completion systems allow a larger number of stages over multiple intervals. This method affords more precise placement of stages with reduced spacing down to single-digit feet between zones, a feature that also enables targeting specific pressure characteristics in the reservoir.
Completion selection and well performance analysis were conducted to design a new completion system for production enhancement from Lower Tertiary formations. Design and selection of the lower completion system focused on multi-stage fracturing and potential sand control options, and their impact on production. The following systems were studied to estimate and predict the initial production rates: Multi-Zone Single-Trip (MZST) completion, Large Bore Multi-Zone (LBMZ) completion system and Ball-Activated Fracturing Completion System (BAFCS).
This paper describes a high-level workflow developed for completion design and selection, fracture modeling to generate 3D fracture geometry and fracturing pressures, wellbore design including tubing stress and movement analysis for fracturing treatments and production systems analysis to generate vertical lift performance/inflow performance relationships (VLP/IPR), and to estimate the initial production rates and flowing bottomhole pressure for sand-free production.
The proposed BAFCS used more fracture initiation points (up to 20 stages) in the Lower Tertiary formations when compared to eight individual stages (20 perforation intervals) with MZST and LBMZ completion systems. The more confined fracture geometries were created by using the new proposed multi-stage fracturing system. Predicted BAFCS production rates were higher than those of MZST and LBMZ completion systems. To attain higher production and recovery factors than those achievable with natural depletion, artificial lift options (electrical submersible pumping) were also examined for Lower Tertiary wells.
We investigate the benefits of improving the quantitative estimation of reflectivity in reflection FWI (RFWI). This is an important step of the inversion process, since it not only affects the generation of the synthetic reflection data, but also the generation of the “rabbit ears�? along the reflection wavepaths. In our approach, the quantitative estimation of reflectivity is performed using least-squares reverse time migration (LSRTM), where the Hessian matrix and its inverse are estimated in the curvelet domain. Using synthetic and field data sets, we show how this approach can improve the reflectivity model and, therefore, benefit the RFWI velocity update. Finally, we discuss some of the limitations of this approach and some of the challenges that are not addressed by it.
Presentation Date: Thursday, October 18, 2018
Start Time: 8:30:00 AM
Location: 207C (Anaheim Convention Center)
Presentation Type: Oral
Zhang, Tianze (Missouri University of Science and Technology) | Lin, Yani (Missouri University of Science and Technology) | Liu, Kelly H. (Missouri University of Science and Technology) | Gao, Stephen S. (Missouri University of Science and Technology)
Summary The Lower Wilcox strata are proven to be a good quality reservoir along the Central Gulf Coast of Texas. However, the complexity of its sedimentary environment makes it hard to accurately locate the isolated productive sand. In this study, rock physics analyses are carried out to provide a better understanding of the reservoir properties. Bulk density, P-wave velocity, and elastic moduli are extracted from four wells for analyzing the depth and temperature effects on compaction. A combination of three effective medium models is used for cement volume diagnostics.
Mullins, Oliver C. (Schlumberger) | Primio, Rolando Di (Lundin) | Zuo, Julian Y. (Schlumberger) | Uchytil, Steve (Hess) | Mishra, Vinay K. (Schlumberger) | Dumont, Hadrien (Schlumberger) | Pfeiffer, Thomas (Schlumberger) | Achourov, Vladislav V. (Schlumberger) | Pomerantz, Andrew E. (Schlumberger) | Forsythe, Jerimiah (Schlumberger) | Betancourt, Soraya S. (Schlumberger) | Elshahawi, Hani (Shell)
Petroleum system modeling provides the timing, type and volume of fluids entering a reservoir, among other things. However, there has been little modeling of the fluid processes that take place within the reservoir in geologic time, yet these processes have a dramatic impact on production. Modeling and understanding of the reservoir then reinitiates with simulation of production for optimization purposes. The new discipline "reservoir fluid geodynamics" (RFG) establishes the link between the petroleum system context or modeling and present day reservoir realizations. This new discipline has been enabled by scientific developments of the new asphaltene equation of state and by the technology of downhole fluid analysis (DFA). Gas-liquid equilibria are treated with the traditional cubic EoS. Crude oil fluid- asphaltene equilibria are treated with the Flory-Huggins-Zuo equation of state with its reliance on the Yen-Mullins model of asphaltenes. Thermodynamic treatment is essential in order to identify the extent of equilibrium in oil columns, thereby identifying fluid dynamics in geologic time. DFA is shown to be very effective for establishing asphaltene gradients vertically and laterally in reservoir fluids with great accuracy. In turn, this data tightly constrains the thermodynamic analyses. These methods have been applied to a large number of reservoir case studies over a period of ten years. For example, case studies are shown that indicate baffling and lower production for parts of the reservoir that have slower rates of fluid equilibration. In addition, the newly revealed lateral sweep in trap filling is established via RFG case studies. Underlying systematics, especially for gas charge into oil reservoirs, have been revealed for a large number of fluid and tar distributions that enable a unifying and simplified treatment for seemingly intractable complexities. A case study is presented that shows three very different reservoir realizations in adjacent fault blocks for the same petroleum system model, where RFG explains all these differences. This enables key reservoir properties to be projected away from wellbore in ways not previously possible. Finally, universal work flows are shown which enable broad application of these methods through all phases of reservoir exploration and production.
The drilling of Eagle Ford horizontal wells in Karnes and DeWitt counties traditionally requires at least two bottomhole assembly (BHA) configurations to drill from surface casing to reach total depth (TD). After a few initial successful attempts at drilling from surface casing to TD using a single BHA (one-run), several problems were encountered, resulting in multiple unsuccessful one-run attempts. What began as a study to determine the best bit for one-run applications evolved into a multivariable study to identify the key factors for achieving successful one-run wells.
The success rate of one-run wells increased from 25 to 85% over a seven-month period. Achieving this level of success involved analyzing vertical parameters (specifically through the highly abrasive Wilcox formation), geographic location (correlated with Wilcox formation thickness), motor bend, BHA components, well trajectory, bit selection, and overall well length. Improving the efficiency of drilling Eagle Ford wells with a one-run application proved to be most dependent on the optimization of vertical parameters, Wilcox thickness, and overall well length.
The method and recommendations presented in this paper are most applicable on land. Wells with geologic formations and temperature ranges that can tolerate necessary variations in mud parameters throughout the vertical, curve, and lateral sections should be seriously considered. One-run wells can prove profitable by sacrificing a section rate of penetration (ROP) to gain overall well ROP. For example, a slight reduction of the drilling parameters in the vertical section may reduce the vertical ROP, but will maintain the BHA integrity for the curve and lateral sections, which will result in an increased ROP for the length of the well.
Significant reductions in rig time and the amount of equipment used resulted in an overall increased economic efficiency dependent on time and costs associated with tripping and picking up a new BHA. In addition, eliminating a trip for a new BHA is a simpler operation and, consequently, provides a safer work environment for rig personnel.
Mehmani, Ayaz (Department of Petroleum and Geosystems Engineering, The University of Texas at Austin) | Milliken, Kitty (Bureau of Economic Geology, The University of Texas at Austin) | Prodanovic, Maša (Department of Petroleum and Geosystems Engineering, The University of Texas at Austin)
A process-based multiscale network modeling approach is introduced to predict the drainage capillary pressure and relative permeability-wetting phase saturation curves at early cementation, final cementation and feldspar dissolution of the Wilcox tight gas sandstone. Predictions based on a two-scale analysis of an X-ray tomographic image are conducted as well but computational limitations make conclusions uncertain in this paper. We emphasize process-based modeling informed from thin sections as a cheap method of making a priori predictions of tight gas sandstone transport properties at various times in the paragenesis.
Deepwater and ultradeepwater completions employ numerous hydraulic control lines for operating downhole equipment as the primary method of actuation or as back-up systems for control and actuation. Incorporating a completion system with an in-well lift, i.e., electric submersible pumps (ESPs), increases the number of electrical lines that are needed for operation. The total number of control and electrical lines maximizes the number of hydraulic and electrical lines that can be terminated back to the tubing hanger and wellhead. On surface, managing and running the numerous control lines can be daunting. Weight and size limitation and available rig floor, deck, and sub-deck space must be considered when planning placement of reeled lines, back-up systems, and preparation of supporting systems for spooler and reels.
In this paper we discuss the planning and execution of an installation test conducted in close collaboration with an operator. This stack-up test was conducted to determine whether a completion system incorporating a dual canned ESP system with multiple control lines can be efficiently and safely deployed in a deepwater, high-pressure/high-temperature (HPHT) environment.
The completion system uses numerous hydraulic control lines, tubing encapsulated conductor (TEC) lines, and ESP electrical cables to support the various downhole completion equipment systems. The control lines and cables are various sizes and shapes, further complicating their manageability. Testing was successfully performed in a 500-ft test well on a land rigand the equipment and processes used were deemed scalable to a drillship operating in deep water. Results of the test suggest that safely deploying a dual canned ESP system in a deepwater well is possible. Doing so would bring increased revenue from the additional years of production enabled by the dual canned ESPs.