Executive Summary

This month, SPE Journal publishes 30 new papers, organized in four categories.

Flow Assurance. Flow assurance plays a key role in production of oil and gas, especially in the deepwater environment.  Hydrates, asphaltene, wax, emulsions, erosion, and sludge are amongst the key flow-assurance issues. The first 10 papers in this issue deal with these aspects of flow assurance.

Sun et al. investigate the morphology and rheology of hydrate slurry with hydrate concentrations from 6 to 11% and shear rates from 20 to 700 s–1. Their work on hydrate slurry exhibits shear-thinning behavior in low-shear-rate conditions and shear-thickening behavior in high-shear rate conditions. The critical shear rate is proposed to describe the transition between the shear-thinning and shear-thickening behaviors of the hydrate slurry. Empirical Herschel-Bulkley-type equations are developed to describe the rheology of the hydrate slurry for both conditions.

To study the characteristics of methane hydrate formation in drilling fluid, Fu et al. carry out experiments with methane hydrate formation in water with carboxmethylcellulose (CMC) additive in a horizontal flow loop under flow velocity ranging from 1.32 to 1.60 m/s and CMC concentration from 0.2 to 0.5 wt%. The experiments indicate that the increase of CMC concentration impedes the hydrate formation while the increase of liquid velocity enhances formation rates. A semi-empirical model that is based on the mass transfer mechanism is developed for current experimental conditions. The overall hydrate formation coefficient in the proposed model is correlated with experimental data.

Nunez et al. study emulsions in a portable dispersion characterization rig, whereby the separation kinetics are observed and recorded. In this study, emulsion breakup by the integration of oil extraction/water addition and a stirring process is investigated, which is formed with 25% water cut and 0.01% w/w hydrophobic nanoparticles (dispersed in the oil phase). The experimental data are divided into three data sets: oil extraction only, oil-extraction/pure-water addition, and oil-extraction/water with hydrophilic nanoparticle addition.

Khodaparast and Johns show that microemulsion viscosities associated with the three-phase invariant point have an M shape as formulation variables change, such as from a salinity scan. The location and magnitude of viscosity peaks in the M are predicted from two percolation thresholds after tuning to viscosity data. On the basis of these correlations, two- and three-phase microemulsion viscosities are determined in five-component space (surfactant, two brine components, and two oil components) independent of flash calculations. Phase compositions from the equation-of-state flash calculations are entered into the viscosity model.

Ratnakar et al. examine the changes in interfacial properties (such as contact angle between the live-oil, brine, and quartz system) as well as surface topography and compositions caused by asphaltene precipitations that are related to pressure-depletion processes.  This is the first experimental evidence that pressure-depletion-driven asphaltene precipitation alters the contact angle at realistic reservoir conditions (high-pressure, high-temperature live oils). These data can be used as a basis to establish the benchmark data, model calibration for managing and preventing remediation asphaltene problems, and to design the proper facility and operating conditions for efficient recovery and operational processes.

Hirpa et al. investigate the transport of sand particles over the sand bed deposited in a horizontal conduit by using turbulent flow of water. These tests are carried out to determine (1) the near-wall turbulence characteristics at the onset of bed erosion (i.e., near-wall velocity profile, Reynolds shear stresses, and axial-turbulent intensity);  (2) critical velocity required for particle removal from the bed deposits; and (3) how the sand-particle size and surface characteristics would influence the critical velocity required for the onset of bed erosion and the near-wall turbulence characteristics. The results indicated that critical velocity for the onset of particle removal from sand beds increased with the increasing particle size. When sands with special surface treatment were used, it was observed that the critical velocity required for the onset of the bed erosion was significantly lower than that required for the untreated sands.

Zhong et al. discuss the feasibility and performance of sludge injection into steam-stimulated wells. They report that sludge sequestration has been applied to 45 steamed wells in Shuguang Oilfield until 2018, and all the wells have been stimulated by 7–10 cycles of cyclic steam stimulation. The total sludge injection of the wells is up to 133,200 tons, and more than 15,000 tons of oil and solids separated from the sludge are deposited underground. At the same time, more than 20% increase in cyclic oil production on average is obtained by the sludge-injection process.

Heat loss along pipeline could worsen the unfavorable hydrate and wax depositions. Park et al. experimentally verify a formula for the modified overall-heat-transfer coefficient (OHTC) that considers multilayered soil conditions for steady-state subsea pipelines. A laboratory-scale experiment is conducted to simulate the flows of cold seawater and hot crude oil inside the pipes immersed in multilayered soils at nine burial-depth rates. The obtained results are in good agreement with the data obtained by a previously derived OHTC analytical formula.

Chen and Yang extend the ideal mixing rule with effective density (IM-E) to condensate/bitumen systems, solvent/bitumen fraction systems, and solvent/bitumen systems with substantial extraction by properly treating the densities of condensate, bitumen fractions, extracts, and residues. This study focuses on heavy-oil/bitumen-associated systems.

High-viscosity liquid two-phase upward vertical flow in wells and risers presents a new challenge for predicting pressure gradient and liquid holdup due to the poor understanding and prediction of flow pattern. Al-Safran et al. propose new transition models for predicting the pressure gradient. A validation study of the proposed models against the entire high-viscosity liquid experimental data set reveal a significant improvement with an average error of 22.6%. Specifically, the model overperforms existing models in BL/INT and INT/AN pattern transitions.


Drilling & Completion. Flow properties of drilling mud, their high temperature integrity, acid fracturing, cuttings transport, coal seam identification, and drilling-fluid cleanup are amongst the topics covered by these papers.

Wiktorski et al. study the implicit effects of temperature and wellbore tortuosity on the mechanical friction factor in torque-and-drag models used for straight inclined sections. Experimental work is performed to measure the variation of viscosity and density of a water-based-mud sample with respect to temperature and pressure. By including additional parameters in the traditional torque-and-drag models, researchers and engineers would be able to evaluate the effects of these parameters on the friction-factor estimation.

Liu et al. discuss the role of polymeric additives in improving the ultrahigh-temperature tolerance of bentonite-based drilling fluids, aiming to provide practical and efficient solutions to the failure of drilling fluids in high-temperature conditions. By adding PSS (polysodium 4-styrenesulfonate) to the original drilling fluid containing bentonite, significant fluid loss—as a consequence of bentonite-particle flocculation causing drilling-fluid shear-stress reduction and high-permeability mud—is successfully suppressed even at a temperature as high as 200°C. This drilling fluid containing PSS was applied in the drilling of high-temperature deep wells in China, and it exhibited high effectiveness in controlling accidents including overflow and leakage.

Toolless temporary-plugging multistage acid fracturing of horizontal wells is a necessary technology to unlock the production potential and enable commercial productivity for tight carbonate reservoirs. Zhang et al. propose an integrated method to experimentally study toolless multistage fracturing with diverters.

Zhang et al. present an approach that combines a 2D computational fluid dynamics (CFD) and 1D continuous model for cuttings transport simulation during drilling of oil and gas wells. The 2D CFD simulates the flow profile and the suspended cuttings concentration profile in the cross section of the wellbore and the 1D continuous model simulates the cuttings transportation in the axial direction of the wellbore.

Accurate coal identification is critical in coal seam gas (CSG) (also known as coalbed methane or CBM) developments because it determines well completion design and directly affects gas production. Density logging using radioactive source tools is the primary tool for coal identification, adding well trips to condition the hole and additional well costs for logging runs. Zhong et al. use machine learning methods to identify coals from drilling and logging-while-drilling data to reduce overall well costs. After placing slotted casings, all wells have coal identification rates greater than 90%, and three wells have coal identification rates greater than 99%. This indicates that machine learning methods can be an effective way to identify coal pay zones and reduce coring or logging costs in CSG developments.
Meng et al. develop an oil-in-water nanoemulsion for the effective removal of an oil-based drilling fluid by means of the phase-inversion concentration method. The influence of four factors on the droplet size and removal efficiency were tested, including the mass ratio of mixed surfactants, the surfactant/oil ratio, the mass concentration of cosurfactant, and the salinity of the saline solution. The results indicate that the nanoemulsion could spread rapidly and thoroughly on the oil-wetting surfaces, and the nanoemulsion can contain more oil while the system is still stable, which is beneficial for the removal of an oil-based drilling fluid.

Ali and Nasr-El-Din introduce a novel approach to predicting the performance of acid treatments in the field using log data only. A radial reactive flow simulator, using porosity distributed from logs, is used to provide accurate predictions without the need for experiments. The reactive flow simulator was able to accurately capture wormhole propagation inside the linear core. This work introduces an accurate model using porosity directly from logs to predict acid performance while avoiding expensive designs. The simulation results reveal that traditional designs overpredict acid volumes required for field treatments. 

Lu and Reynolds develop an algorithm that is based on machine learning to find the optimal choices of drilling paths, types, and drilling order. A binary encoding for the optimization variables pertaining to well-location indices and well types is proposed to effectively handle a large number of categorical variables, while the drilling sequence is parameterized with ordinal numbers. These two sets of variables are optimized both simultaneously and sequentially. Finally, control optimization using a stochastic simplex approximate gradient is performed to further improve the NPV of life-cycle production.

Discharging drilling cuttings into the seabed is one way of reducing drilling costs. Sun et al. provide a model that can quantitatively characterize the functional relationship between characteristics of cuttings piles and relevant parameters (current velocity, cutting size, evolution time), and predict the location and geometry characteristics of the cuttings piles evolving into a stable state in ocean currents. Comparing the measured data in laboratory experiments and at an offshore drilling field, the relative error of the model amounts to less than 10%, which demonstrates its rationality.

Gautam and Guria also investigate increasing the thermal stability of drilling mud. They use polyanionic cellulose-grafted copolymers with salt-tolerant viscosifying agent, thermally stable lubricating, fluid-loss control agent, and high-temperature deflocculant to maximize the thermal degradation stability of the grafted copolymer and minimize the filtration loss as well as the coefficient of friction of the drilling fluid simultaneously. Optimally synthesized copolymers are then used to prepare water-based mud involving American Petroleum Institute-grade bentonite and alpha-glycol functionalized nano fly ash. Thus, they were able to extend the rheological stability of mud beyond 200°C.


Unconventional Resources. Five papers have been selected in this issue that deal with the impact of pyrolysis on shale oil, phase behavior, and rock permeability prediction.

Ghanizadeh et al. carry out similar tests with cores from Duvernay Formation to investigate the effect of entrained hydrocarbon/organic matter on storage and transport properties of the organic-rich shales. They use sequential pyrolysis on core samples and compare the results before and after testing.

Kim et al. carry out maturation of source rocks (oil shale) artificially via pyrolysis under geologically realistic triaxial stresses using a unique coreholder that is compatible with X-ray computed tomography (CT) scanning. This study focuses on characterization of porosity and permeability as well as the evolution of shale fabric during pyrolysis. The measured 3D in-situ porosity distribution indicates that organic matter has transformed into hydrocarbons by pyrolysis. The development of a fracture and matrix porosity system under stress provides an explanation for transport of hydrocarbon away from its point of origin.

Luo et al. investigate the nanoscale pore size effect on fluid phase behavior using Anadarko Basin shale oil. The pore-size distribution is discretized as a multiscale system with pores of specific diameters. The phase equilibria of methane injection into the multiscale system are calculated. It is found that fluid in nanopores becomes supercritical with injected gas, but lowering the pressure to less than the bubblepoint turns it into the subcritical state. The bubblepoint is generally lower than the bulk and the degree of deviation depends on the amount of injected gas.

To accurately predict the apparent permeability of shale, Wang et al. couple molecular dynamics and a pore-network model to develop a multiscale framework for gas flow through shales. First, they use nonequilibrium molecular dynamics to study the pressure-driven flow behavior of methane through organic, calcite, and clay nanopores under reservoir conditions. Then, they propose a mass-transport model accounting for the contributions of both the adsorbed-phase fluid and bulk fluid. They also develop an analytical model for the apparent permeability of shale matrix using the bundle-of-capillaries approach.

Radio-frequency (RF) heating of the in-place oil shale has previously been proposed as a method by which the electromagnetic energy gets converted to thermal energy, thereby heating in-situ kerogen so that it converts to oil and gas. To numerically model the RF heating of the in-situ oil shale, Ramsay developed a novel explicitly coupled thermal, phase field, mechanical, and electromagnetic (TPME) framework using the finite-element method in a 2D domain.

Geomechanics.  Five papers in this issue deal with application of newly developed models to simulate wellbore integrity under in-situ stress conditions, fault reactivation, fracture properties, and impact of rock crushing under reservoir dynamic loading.

Meng et al. propose a fully coupled poroelastodynamic model to study wellbore behavior. This model not only considers fully coupled deformation/diffusion effects, but also includes both solid and fluid inertia terms. The implicit finite-difference method is applied to solve the governing equations, which allows this model to handle all kinds of dynamic loading conditions. The results show that the inertial effect is insignificant for tripping and a fully coupled, quasistatic model is recommended for wellbore stability under tripping operations. The fully coupled poroelastodynamic model should be used for rapid dynamic loading conditions, such as earthquakes and perforations.

Liu et al. propose a semianalytical model to estimate the length of slippage along the fault that is caused by pressurization of a fault intercepted by hydraulic fracturing. Two fault-slippage cases were calculated to assess the casing failure in nearby wells. The presented model may be used as a tool for quick estimation of the magnitude of fault slippage upon intersection with a hydraulic fracture, to avoid potential casing failures, and to obtain a more reliable spacing selection in the wells intersecting faults.

Zou et al. simulate the hydraulic-fracture-propagation process during temporary-plugged fracturing (TPF) in a naturally fractured formation using a previously developed 3D discrete-element-method-based complex fracture model. Plugged fracture elements with negligible permeability are incorporated into the model to characterize the blocking intervals of diverting agents within hydraulic fractures. The results of this study help to understand the hydraulic-fracture-growth mechanism during TPF and help to optimize the treatment design of TPF and to adjust it in a timely manner.

Liu et al. propose an efficient coupled flow and geomechanics model to characterize the dynamic fracture properties and examine their effects on well performance and stress evolution in complex fractured shale-gas reservoirs. A unified compositional model with nonlinear transport mechanisms is used to accurately describe multiphase flow in shale formations. The embedded discrete fracture model (EDFM) is used to explicitly model the complex fracture networks. Different fracture constitutive models are implemented to describe the dynamic properties of hydraulic fractures and natural fractures, respectively.

Sun et al. develop a numerical model to deal with crushable stiff and soft grains (proxies for sand and shale) simulated with the discrete element method coupled with the bonded-particle model. Reservoir simulations—incorporating the change of porosity and permeability as a compaction table—showed that the compaction can enhance cumulative production due to compaction drive but also reduces production rate by impairing the reservoir permeability. This multiscale numerical workflow bridges grain-scale compaction behavior and field-scale reservoir production.

Reza Fassihi, SPE J. Executive Editor;
BHP Petroleum, Houston