Modern multifractured shale-gas/oil wells are horizontal wells completed with simultaneous-fracturing, zipper-fracturing, and (in particular) modified-zipper-fracturing techniques. An analytical model was developed in this study for predicting the long-term productivity of these wells under conditions of pseudosteady-state (PSSS) flow, considering the cross-bilinear flow in the rock matrix and hydraulic fractures. Performance of the model was verified with the well-productivity data obtained from a shale-gas well and a shale-oil well. Sensitivity analyses were performed to identify key parameters of hydraulic fracturing affecting well productivity. The conducted field case studies show that the analytical model overpredicts shale-gas-well productivity by 2.3% and underpredicts shale-oil productivity by 7.4%. A sensitivity analysis with the model indicates that well productivity increases with reduced fracture spacing, increased fracture length, and increased fracture width, but not proportionally. Whenever operational restrictions permit, more fractures with high density should be created in the hydraulic-fracturing process to maximize well productivity. The benefit of increasing fracture width should diminish as the fracture width becomes large. Increasing fracture length by pumping more fracturing fluid can increase well-production rate nearly proportionally. Therefore, it is desirable to create long fractures by pumping high volumes of fracturing fluid in the hydraulic-fracturing process.
In past years, the industry has focused on ensuring that cement is efficiently placed in the wellbore and that it does not become mechanically damaged during the life of the well. However, few efforts have been made to determine how cement mechanical integrity (CMI) relates to cement hydraulic integrity (CHI) (i.e., evaluating the flow rate that could occur through the cement barrier), even though CHI is one of the main objectives of placing a cement plug in a wellbore.
The analysis of hydraulic integrity requires that a CMI model be used to compute the state of stress and pore pressure in the cement and to estimate which type of mechanical failure might occur during the life of the well. It also requires that a CHI model be integrated with the CMI model to estimate the rate of fluid that might flow through a cement barrier, should it mechanically fail. This provides the engineer with insight into the long-term integrity of a cement plug.
This paper describes the work conducted on CMI/CHI models for cement plugs, and it presents a sensitivity analysis that demonstrates the value of an integrated CMI/CHI model. The study indicates that (1) well geometry, cement properties, reservoir pressures, cement heat of hydration, and fluid properties are required inputs for proper analysis; (2) the changes of stresses and pore pressure over time need to be computed along the length of the cement plug, with sensitivity analysis to consider the existing uncertainties; (3) a cement plug might preserve its sealing capability, even if the CMI model shows the existence of a microannulus (e.g., when the fluid viscosity is very high); and (4) a cement plug might lose its sealing capacity, even if the CMI model shows no induced defect (e.g., when a microannulus is propagated as a hydraulic fracture).
These last two observations are important because they show that what a CMI model cannot predict, a CHI model can.
Burton, Robert C. (ConocoPhillips) | Gilbert, W. W. (ConocoPhillips) | Fleming, Graham (ConocoPhillips) | Leitch, John C. (ConocoPhillips) | Nozaki, Manabu (ConocoPhillips) | Pandey, Vibhas J. (ConocoPhillips) | Adams, Matt D. (ConocoPhillips) | Peterson, Erick M. (ConocoPhillips) | Zhou, Leon (ConocoPhillips) | Ray, Tony W. (ConocoPhillips)
A nine-well subsea development project has been completed using casedhole frac packs (CHFPs) for sand control and multizone intelligent-well systems (IWSs) to improve recovery from a series of shallow, low-pressure gas reservoirs. In these wells, CHFPs have been installed to provide reliable sand control over the long, low-net-to-gross-ratio sand/shale target sequence: typically, three to six frac packs per well. This outer CHFP completion is then augmented with a multizone IWS, consisting of isolation seals, surface-controlled zonal-isolation valves, and downhole-pressure/temperature (DHP/T) gauges. The IWS string is run as a separate inner string to provide flow-monitoring capability and allow shutoff of zones producing high water volumes. This critical water-shutoff capability eliminates the risk of one or more high-water-production zones loading up and killing adjacent low-pressure gas zones, with the associated loss of reserves.
To date, a total of nine wells have been completed and are being produced from three subsea gas fields. To maximize recovery from the fields’ numerous but relatively thin gas reservoirs, production wells are completed over three to six separate intervals. These frac-packed intervals are then grouped to allow flow control and pressure/temperature monitoring to occur through up to six surface-operated interval control valves (ICVs) and associated downhole gauges. This combination of sand control and intelligent-well control has provided an ability to perform multirate tests (MRTs) and pressure-buildup (PBU) tests on each reservoir interval to detect the start of water production or identify other impending production issues. After approximately 6 years of production service to the October 2018 date of this paper, 16 of the 34 zones completed in the nine-well project have been shut in to eliminate high water production. These water-shutoff actions performed using the surface-controlled ICVs are estimated to have improved gas-recovery factors from 50 to 60% without requiring rig intervention.
This paper describes the reservoir challenges addressed and the completion-design and -operating practices used in this successful program.
Al Saedi, Ahmed Q. (Missouri University of Science and Technology ) | Flori, Ralph E. (Missouri University of Science and Technology ) | Kabir, C. Shah (Missouri University of Science and Technology and University of Houston)
Temperature-profile distributions in a wellbore during drilling operations might take different forms when applying the energy balance in the overall system. For steady-state conditions, wherein the wellbore is considered a closed system, adding any source of additional energy to this system can influence the predicted temperature profiles. This study presents a new analytical model to investigate the influence of rotational energy arising from the drillstring operation on the wellbore-temperature behavior.
A significant part of the drilling operation is rotation of the drillstring. Depending on the drilling rig, various equipment provides this kind of energy, such as the rotary table or topdrive. In addition, downhole motors or turbines can add additional rotation to the drill bit. This type of energy source can be construed as a supplemental heat source that could be added to the formulations of drillpipe- and annular-temperature profiles.
Overall, this study presents two models involving frictional and rotational energy. These models yield the same solution if we do not include the energy source, and they can apply equally well for any energy-balance system. The proposed mathematical models provide new insights into different energy terms that can be included to compute the temperature profiles in the drillpipe and annulus.
This paper focuses on the application of polyelectrolyte-complex (PEC) nanoparticles to fluid-loss control of oilwell cements. Cement-slurry design involves considerable complexities, including the interplay of viscosity, yield point (YP), fluid-loss control, setting time, sedimentation, gel-strength development, and density. Polymers such as hydroxyethyl cellulose (HEC), carboxymethyl HEC (CMHEC), and polyvinyl alcohol have been used extensively for fluid-loss control in oilwell cementing. However, the resulting increase in slurry viscosity often led to unwanted side effects, such as increased pumping requirements. PECs were originally developed as drug carriers for pharmaceutical applications. Our previous work (Cordova et al. 2008; Lin et al. 2014; Johnson et al. 2016) showed that they can also be effective in improved-oil-recovery applications. In this study, we explore the potential of using PEC nanoparticles to achieve effective fluid-loss control while maintaining good fluid properties of the cement slurry. Results from this proof-of-concept study demonstrated that a PEC system comprising common oilfield polymers can be used to achieve effective fluid-loss control. Simultaneously, the system shows improved rheological properties over control samples while maintaining other desirable slurry characteristics.
Offshore wells drilled in the central and northern North Sea have historically suffered from borehole-instability problems when intersecting the Upper/Lower Lark and Horda Shale formations using either water-based mud (WBM) or oil-based mud (OBM). A wellbore-stability investigation was performed that focused primarily on improving shale/fluid compatibility. It was augmented by a look-back analysis of historical drilling operations to help identify practical solutions to the borehole-instability problems.
An experimental rock-mechanics and shale/fluid-compatibility investigation was performed featuring X-ray-diffraction (XRD) and cation-exchange-capacity (CEC) characterizations, shale accretion, cuttings dispersion, mud-pressure transmission, and a new type of borehole-collapse test for 10 different mud systems [WBM, OBM, and high-performance WBM (HP-WBM)]. The results of this investigation were then combined with the results of a well look-back study. The integrated study clearly identified the root cause(s) of historical well problems and highlighted practical solutions that were subsequently implemented in the field.
The borehole-instability problems in the Lark and Horda Shales have a characteristic time dependency, with wellbore cavings occurring after 3 to 5 days of openhole time. The problems were not related to mud-weight selection but were instead caused by mud-pressure invasion into the shales, which destabilizes them over time. An experimental testing program revealed that this effect occurs in both WBM and OBM to an equal extent, which explains why nonoptimal field performance has historically been obtained with both types of mud systems. New HP-WBM formulations were identified that improve upon the mud-pressure invasion and borehole-collapse behavior of conventional OBM and WBM systems, yielding extended openhole time that allows the hole sections in the Lark and Horda Shales to be drilled, cased, and cemented without triggering large-scale instability. Look-back analysis also indicated that secondary causes of wellbore instability, such as barite sag, backreaming, and associated drillstring vibrations, should be minimized for optimal drilling performance. A new HP-WBM system, together with improved operational guidelines, was successfully implemented in the field, and the results are reported here.
The authors of SPE - 180322 - PA [ SPE Drill & Compl 33 (1): 63 - 76. https://doi.org/10.2118/180322 - PA ] have submitted the following corrections to the paper . The information herein supersedes that in the original ly published paper. The pressure term in Eq. 9 on page 65 represents the total pressure and the superscript "*" must be removed. A - 6 on page 76 should not have a negative sign.
Currently, there is large-scale shale gas exploration and development in the Sichuan Basin, western China. Caused by high tectonic stress and presence of fracture systems at various scales in the lower Silurian Longmaxi reservoir formation, hydraulic fracturing in shale gas reservoirs in the Sichuan Basin has encountered many difficulties, such as placing sufficient proppant, poor-production performance for some wells, and ambiguity as to the factors controlling the production of reservoirs. It has been recognized that lack of geomechanical understanding of the shale gas reservoirs is a major obstacle to effectively addressing these difficulties.
A 3D full-field geomechanics model was constructed for the Changning shale gas reservoir in the Sichuan Basin through integrating seismic, geological structure, log, and core data by following a newly formulated work flow. The 3D geomechanical model includes 3D anisotropic mechanical properties, 3D pore pressure, and the 3D in-situ stress field. Through leveraging measurements from an advanced sonic tool and core data, the anisotropy of the formation was captured at wellbores and propagated to 3D space guided by prestack seismic inversion data. The 3D pore-pressure prediction was conducted with seismic data, and calibrated against pressure measurements, mud-logging data, and flowback data. A discrete-fracture-network (DFN) model, which represents multiscale natural-fracture systems, was integrated into the 3D geomechanical model during stress modeling to reflect the disturbance on the in-situ stress field by the presence of the natural-fracture systems.
The 3D pore-pressure model was used to calculate more-reliable estimates of gas in place in the shale gas reservoir, and the geomechanical model was used to reveal the root cause of difficulties of proppant placement in this tectonically active and unevenly fractured shale gas reservoir.
The paper presents the highlights and innovations in constructing the 3D geomechanical model for the shale gas reservoir, and explains how the 3D geomechanical model is used to address technical challenges encountered during drilling and completion. Also, it demonstrates that a reliable 3D geomechanical model, with proper characterization of anisotropy, pore pressure, and natural fractures, provides a critical opportunity to improve the development in this shale gas reservoir.
Omar Mahmoud and Hisham A. Nasr-El-Din, Texas A&M University, and Zisis Vryzas and Vassilios C. Kelessidis, Texas A&M University at Qatar Summary During the past few decades, nanoparticles (NPs) have been investigated as additives to address the challenges of drilling fluids and have shown potential for application. Computedtomography (CT) scan and scanning electron microscopy energy dispersive spectroscopy (SEM-EDS) were used for filter-cake characterization. The effects of NP concentration and filtration conditions on the filter-cake properties were investigated. A highpressure/high-temperature (HP/HT) American Petroleum Institute (API) filter press was used to perform static and dynamic filtrations. Indiana limestone disks were used as filter media to simulate formation behavior. NPs/Ca bentonite fluid showed improved filter-cake and filtration properties in the presence of polymers and other additives. A concentration of less than 1 wt% of NPs is preferred for generating a good-quality filter cake. The best characteristics were obtained when using an NP concentration of 0.3 to 0.5 wt%. The NPs/Ca bentonite-based drilling fluid can withstand conditions up to 500 psi and 350 F and generate filter-cake properties of 0.151-in. NPs improved the filter-cake properties under both static and dynamic conditions. SEM-EDS showed a smoother/lessporous filter-cake morphology with less agglomeration when using NPs at optimal concentrations, which confirms that the NPs play a key role in forming a better filter-cake structure. The present work provides an experimental evaluation of the filter cake generated by modified NPs/Ca bentonite-based drilling fluid at downhole conditions, which is an extension of our previous work using a simple NPs/Ca bentonite suspension (Mahmoud et al. 2018).
Wang, Xueying (China University of Petroleum, East China) | Ni, Hongjian (China University of Petroleum, East China) | Wang, Ruihe (China University of Petroleum, East China) | Wang, Peng (China University of Petroleum, East China) | Zhang, Lei (China University of Petroleum, East China)
Tool-face control is an important issue when drilling directional wells with steerable motors. Although extensive knowledge about toolface orientation is available, the mechanisms of tool-face disorientation during slide drilling are not completely understood. Surface-rotation pulses can correct tool-face orientation (Maidla and Haci 2004), but the underlying mechanism, in our view, remains unclear. This paper proposes a drillstring model to analyze the mechanisms underlying tool-face disorientation and correction.
Our drillstring model is based on the finite rigid-body assumption with a mixed friction model that incorporates Stribeck’s friction curve. The simulation results indicate that tool-face hysteresis caused by the difference in the higher loading rate and lower unloading rate of reactive torque is an essential factor in tool-face disorientation. In addition, a harder formation is more prone to inducing toolface disorder. The process of tool-face correction can be divided into three stages, and the position of the vanishing point of reactive torque determines the effectiveness of the surface-rotation pulse. The tool face turns clockwise only if the applied rotation pulse drives the vanishing point of reactive torque downward to the bit.
The simulation results and analysis are useful for understanding drillstring behavior during slide drilling and further improving the efficiency of tool-face control.