Kuang, Yuchun (Southwest Petroleum University, China) | Luo, Jinwu (Southwest Petroleum University, China) | Wang, Fang (Southwest Petroleum University, China) | Yang, Yingxin (Southwest Petroleum University, China) | Li, Shu (Sichuan Deep and Fast Oil Drilling Tools Company Limited) | Zhang, Liang (Sichuan Deep and Fast Oil Drilling Tools Company Limited)
The powdery or laminar cuttings that are produced by a conventional polycrystalline-diamond-compact (PDC) bit are not suitable for geological logging. To solve this problem, this paper introduces a new PDC bit with suction-type minicore drills. The basic working principle of this new PDC bit is to remove the main cutters in the center of the PDC bit. The new PDC bit can generate minicores of formations with a certain diameter and break these cores in a timely manner during drilling. By use of a special hydraulic design, the broken minicores are sucked from the bottom of the well through the internal coring channel of the bit.
Combined with the theory of rock-breaking simulation and solid/liquid two-phase flow, the effects of different jet-nozzle diameters (6, 8, and 10 mm) on the suction in the coring channel were investigated by considering the quality of the minicores, cuttings, and drilling fluid. The numerical-simulation data show that the cores, cuttings, and drilling fluid that are discharged from the discharge hole have the highest quality if a jet nozzle with a diameter of 8 mm is used. In other words, the suction force generated from the negative-pressure cavity is stronger than that generated with the other two jet-nozzle sizes (6 and 10 mm) investigated.
A test bit was subjected to laboratory and field tests to verify the coring. The experimental results show that the collected cores are generally columnar, and both the integrity and the collection rate of the core are high.
This study demonstrates the feasibility of the concept of the new PDC bit with suction-type minicore drills and provides a design scheme to reduce the coring cost and improve the quality of geological logging.
This work presents a new multivariable controller for management of topside and bottomhole objectives during underbalanced drilling (UBD). A model predictive control (MPC) solution is used to control pressures, rate of penetration (ROP), and flow downhole while also ensuring that the topside processing constraints are respected.
With automated control, it is possible to reduce nonproductive time (NPT), improve safety, and operate closer to the process constraints. MPC is a good fit for UBD because of its easy inherent handling of multiple objectives and constraints. With good pressure control, it is in some cases also possible to reduce the number of casing strings.
The control solution is evaluated through simulations in a high-fidelity multiphase-flow oil and gas simulator (OLGA). It is shown that we can meet multiple objectives both at the surface and at different locations in the well. The optimization problem is solved with good results well within the given time constraints.
The used linear prediction models are relatively easy to understand and maintain. They are also fast and well-suited for optimization and predictions. However, the process is nonlinear, and the linear models will be less accurate as the process conditions change. Retuning or model adaptation might be required to obtain the desired performance. It is possible to include nonlinear models in the control framework, referred to as nonlinear MPC (NMPC), but this will add complexity and require more computational power.
Wellbore tortuosity or spiraling can lead to the trapping of a cuttings bed in a trough of a tortuous hole, thereby leading to poor hole cleaning in extended-reach drilling. The objectives of this study included quantitatively evaluating the influences of wellbore tortuosity on hole cleaning and cuttings-transport behavior in extended-reach drilling. In addition, the study provided a recommendation of effective drilling practices. The study involved performing hole-cleaning-optimization studies for an extended-reach well with a long horizontal section aiming for maximum reservoir contact, by use of a transient cuttings-transport simulator. The planned trajectory of the well was assumed to have a certain degree of wellbore tortuosity in the horizontal section. The pump rate and bottoms-up circulation operation were optimized on the basis of parameter studies and additional transient simulations by considering the effects of penetration rate and variation in cuttings size.
Simulation results indicated the formation of a considerably high cuttings bed, particularly in the downdip intervals (updip in mudflow direction) at an insufficient pump rate; one-third to one-half of the drillpipe diameter could be potentially buried in a cuttings-deposit bed, and this can result in a packed-off hole or stuck pipe. A higher rate of penetration (ROP) can also cause insufficient hole cleaning. In this case, controlled drilling that maintains a reasonably low penetration rate may be effective. Furthermore, borehole breakout may enlarge hole diameter and generate large-sized cuttings. Both of these can have negative impacts on hole cleaning, and, thus, borehole stability and smooth wellbore-trajectory controls should be carefully considered. To clean these holes, frequent bottoms-up circulations were effective at each stand of drilling even if the optimization of other drilling parameters was limited. The findings also revealed that accumulated cuttings in a tortuous wellbore were trapped in the trough of the hole, and that the bed height of locally trapped cuttings in the downdip intervals could be much higher than that indicated by previous studies.
Design of drilling fluids, spacers, cement slurries, and fracturing fluids is often done by trial and error in the laboratory. In the first step, the required properties of these fluids are categorized and then efforts will be started with a rough idea of the optimal composition. This first guess usually depends on the experience of the laboratory analyst or fluid engineer. Afterward, the trial-and-error testing starts, and it continues until the fluid design moves closer to the desired fluid criteria. There are several test data that would not be used in this method, and it is difficult to digest a large amount of information by the user. Trial and error could be time-consuming, very costly, and misleading. Today, there is a need for an intelligent system that uses all the available data (big data), even if the data sets are not close to the desired goal, and offers insights for fluid designs.
This paper conducted a study on the application of machine-learning-based methodologies, including Gaussian-process regression (GPR) and artificial neural networks (ANNs), to reduce the costs of testing, integrate available experimental data, and eliminate the need for personnel supervision. These practical nonlinear-regression methods empower efficient and fast prediction tools that do not require including complex physics of the underlying system while integrating all available data from different sources. GPR, which is also known as Kriging in geostatistics literature, has exceptional advantages over traditional regression methods because it does not require a known form for regression function and also has the capability of determining the estimation error and the confidence interval. This machine-learning-based tool offers insights for intelligent fluid design and could reduce costs.
Estimates of formation pore pressure before and while drilling are important inputs for well planning and operational decision making.
A method is proposed to determine pore pressure from a combination of downhole drilling-mechanics parameters and in-situ rock data with the concept of mechanical specific energy (MSE) and drilling efficiency (DE). This pore-pressure estimation method (termed DEMSE) is based on the theory that energy spent at the bit to remove a volume of rock is a function of in-situ rock strength and the differential pressure that the rock is subjected to during drilling.
A work flow is provided that illustrates the steps required to estimate pore pressure from drilling parameters and rock-mechanics data by use of the DEMSE method. Pore pressure estimated from the DEMSE method is compared with pore-pressure estimates derived through a conventional sonic log that is based on empirical technique for a deepwater well in the Gulf of Mexico (GOM). Pore-pressure estimates from the DEMSE method generally agree in magnitude and trend with the pore-pressure estimates derived from sonic-log data. The results of the DEMSE method have also been compared with pore-pressure estimates from the classical d-exponent (dXc) approach to highlight the advantages of DEMSE over traditional dXc methods.
Finally, the importance of using downhole vs. surface data for pore-pressure estimation purposes, specifically torque measurements at the bit, is illustrated through a field example. These findings suggest that downhole drilling-mechanics data, when properly used, can provide reliable independent estimates of pore pressure in real time at the bit and can be used for post-well-analysis to assist with constructing pore-pressure forecasts.
Yang, Ruiyue (China University of Petroleum, Beijing) | Huang, Zhongwei (China University of Petroleum, Beijing) | Li, Gensheng (China University of Petroleum, Beijing) | Sepehrnoori, Kamy (University of Texas at Austin) | Lin, Qing (China University of Petroleum, Beijing) | Cai, Chengzheng (China University of Mining and Technology)
Steel slotted liners are often used in horizontal coalbed-methane (CBM) well completions. However, the disadvantages associated with these liners, such as high operation costs, corrosion susceptibility, and safety considerations in subsequent mining processes, can limit their performance. One possible alternative is a plastic slotted liner. A major challenge for designing a plastic slotted liner is providing sufficient structural integrity without creating a significant restriction for gas that flows into a wellbore.
In this paper, we present an optimization design for polyvinyl chloride (PVC) slotted liners. Our design couples the influence of the mechanical integrity of the liner and the inflow performance. The optimization parameters are the slot geometrical parameters. The boundary conditions are identified by the failure criteria and the influence of various slot-parameter adjustments through laboratory compression experiments. Two models--a collapse-bearing-capacity model and a skin-factor model (Furui et al. 2005)--are used to optimize the design of the PVC slotted liners. A genetic algorithm is used to maximize the collapse-bearing capacity and minimize the skin factor. Finally, a selection guide for the optimal combination of slot parameters is provided.
The key findings of this work are beneficial for determining the design criteria of plastic slotted liners in horizontal CBM wells. In addition, the proposed “cross-disciplinary” evaluation method is expected to provide a valuable optimization approach for slotted-liner completions.
Water-based-mud (WBM) formulations inclusive of nanosilicas offer the possibility for improved shale inhibition with reduced environmental impact vs. conventional shale inhibitors. These additives may be effective in maintaining well stability and in preventing equipment problems, such as bit balling, which may be experienced in the absence of good shale inhibition.
A series of different nanosilicas has been tested as shale inhibitors in WBMs. Differences in shale inhibition are observed depending on the kind of nanosilica that is used. The nanosilicas described in this article are tested in fresh water and seawater to determine their applicability in both onshore and offshore scenarios. In seawater, nanosilica muds appear to be more powerful inhibitors than silicate/potassium chloride (KCl) muds. The data presented in this report indicate that a nanosilica mud achieves less shale erosion in seawater than a conventional silicate/KCl mud. This increased performance of nanosilica is accompanied with greater ease in handling the lower-pH fluid (which can range from pH 8.5 to 10.0) compared with silicate muds that often exceed pH 12. In addition to being more-potent inhibitors and more safe to handle, nanosilicas offer the possibility of lower environmental cost. High concentrations of KCl are not necessarily required when nanosilicas are included in a mud design for shale inhibition.
Sathuvalli, Udaya (Blade Energy Partners) | Pilko, Robert M (Blade Energy Partners) | Gonzalez, Alexa (Blade Energy Partners) | Pai, Rahul (Blade Energy Partners) | Sachdeva, Parveen (Blade Energy Partners) | Suryanarayana, P. V. (Blade Energy Partners)
Subsea wells use annular-pressure-buildup (APB) mitigation devices to ensure well integrity. We define mitigation techniques that control APB by reducing lateral heat loss from the production tubing to the wellbore as Type I techniques. Mitigation techniques that control the stiffness (psi/F) of an annulus by modifying its contents and boundaries are defined as Type II techniques.
Although the physics of APB mitigation is well-understood, the reliability of a mitigation strategy or its interaction with other parts of the wellbore is not always quantifiable. This is partly because of the lack of a unified approach to analyze mitigation strategies, and partly because of the lack of downhole data after well completion. Simply stated, the engineer is hard-pressed to find computational-predictive methods to assess alternative scenarios and strategies within the framework of the design basis during the life of the well. In this light, our paper presents a quantitative approach to design the currently used APB mitigation strategies: rupture disks, syntactic foams, nitrified spacers, and vacuum-insulated tubing (VIT). In each case, the design is linked to the notion of “allowable APB” in an annulus, which in turn is tied to the design of the casing strings, and thus to wellbore integrity. We also review APB mitigation techniques that have been used less frequently or are awaiting proof of concept/field trial.
The authors have developed a 1D two-layer-model transient-cuttings-transport simulator that predicts the transient behaviors of cuttings transport, including the concentration and slip velocity of suspended cuttings, bed height of cuttings, annular pressure, and equivalent circulating density (ECD) along the entire trajectory of a complex extended-reach well. Model parameters, such as annulus-friction factor, cuttings-deposition rate, and re-entrainment rate, were determined from numerous experiments previously performed by use of a large-scale cuttings-transport flow-loop apparatus. This apparatus simulates the complex flows in borehole annuli at various inclination angles, ranging from vertical to horizontal. In this study, the authors validate the model and analyze the cuttings transport by use of field data in a directional well, in which the annular ECD was measured by logging while drilling (LWD), and the rate of the returned cuttings was measured at the surface. On the basis of the simulation study, the potential of the developed transient-cuttings-transport simulator for the predrilling-and post-drilling-phase analyses is discussed. Moreover, the authors evaluate the transient-hole-cleaning conditions and the ECD behavior from the LWD data.
The offshore Wheatstone liquefied natural gas (LNG) project in Western Australia uses subsea big-bore gas wells as the preferred method of producing the field. Wheatstone wells use a 9 5/8-in. production conduit from the top of the gas pay zone to the ocean floor. Wellbores of this size are necessary to match the large productive capacity of the gas reservoirs they penetrate. This producing scenario provides the obvious benefit of yielding large volumes of gas through the use of relatively few wells. Each of those highly productive wells, however, also represents a source of gas that, if accidentally allowed to flow unhindered, could present an uncommonly difficult well-control challenge. It is for this reason that the Wheatstone Drilling and Completions (D&C) Team evaluated a wide range of possible reservoir- and well-architecture scenarios to fully understand the possible scale of relief-well responses that might be necessary in the event of a blowout. The conclusions from this evaluation were surprising. Our original well-design concept called for penetrating the Wheatstone gas reservoirs with a casing shoe set 3,100 ft vertically above. Our analysis indicated that three or four relief wells would be simultaneously required to bring a blowout under control. Because of these results, both the well- and drilling-execution plan were redesigned to minimize the number of required relief wells. In summary, the redesign amounted to setting the casing immediately (i.e.,<=10 ft) above the gas reservoir before actually penetrating it, with the resulting benefit of reducing the required number of relief wells to two. Although this reduction is beneficial, it should be noted that there is only one documented subsea case where two or more relief wells have been drilled with the intent of simultaneously pumping into both to effect a dynamic kill. Given this fact, our well-control-related preparations for executing this project were more extensive than those of preceding projects.
This paper chronicles the full extent of the engineering and operational planning performed to ensure that no uncontrolled hydrocarbon releases occurred during the execution of the Wheatstone Project’s subsea big-bore gas wells and, if a blowout were to occur, that the response to such an unprecedented event would be sufficient and robust. Covered in this paper are reservoir-deliverability modeling, dynamic-kill modeling, gas-plume modeling, relief-well trajectory and mooring planning, pilot-hole-execution planning, a newly applied logging-while-drilling (LWD) technology for sensing resistivity vertically below the drill bit, and a discussion of future research identified as necessary to better define the fluid-injectivity capabilities of subsea relief wells.