bluuebunny/crossref_metadata_2025 huggingface dataset:
A Fully-Coupled Wellbore-Reservoir Model for Transient Liquid Loading in Horizontal Gas Wells
Authors: Tang Hewei , Hasan A. Rashid , Killough John
Published: October 2017

Liquid loading is a challenging issue in most mature gas fields. The dynamic interaction between wellbore and reservoir when liquid loading happens cannot be comprehensively simulated by a single wellbore simulator or a single reservoir simulator. In this paper, we developed a fully implicitly coupled wellbore/reservoir model to predict the onset of liquid loading and simulate the subsequent unstable production period.

We fully couple a multi-segment well model with an in-house compositional reservoir simulator based on the control-volume finite-difference method. Transient material balance and mixture momentum balance are solved simultaneously with the reservoir system to obtain pressure, mixture velocity, and phase holdup in each wellbore segment. We further proposed a drift-flux model that is able to predict the transitions from stable flow patterns to unstable patterns for different pipe inclinations from vertical to horizontal. The model is applied in the coupled wellbore-reservoir simulator to characterize the two-phase flow in horizontal wellbores. We validate the coupled wellbore-reservoir model with a numerical reservoir simulator and demonstrate the model capability in simulating the whole producing life of liquid-loaded horizontal gas wells. The parametric study indicates that wellbore perforation numbers and joint pipe length before the first perforation can influence the onset time of liquid loading and the duration of unstable production.

Most of previous studies focus on predicting the onset of liquid loading phenomenon. In this paper, our model first achieves the analysis of the unstable production period after liquid loading occurs. The detection of unstable production can be much straightforward comparing to the onset of liquid loading, which makes the model a promising tool in assisting the decision of deliquification strategies for field operators.
Subsea Multilateral Technology Step Change in Australia
Authors: Benson C. A. , Cappiello S. , Campbell B.
Published: October 2017

Because of the substantial cost involved, subsea environments demand technologies which improve efficiency. This statement is particularly true in marginal developments. In such scenarios, multilateral completions have played an integral part in improving field economics through improved well performance and reducing both field and operating costs to a point where the field development is financially appealing. In the northwest shelf of Australia, there have been four major oil field developments to date which have been based either entirely or partially on multilateral completions. This paper describes the evolution of multilateral completions throughout the past 10 years in Australia for two such developments, outlining the efficiency and operational gains during that time period.

Sand face completion techniques in Australia's northwest shelf vary from conventional standalone screens (SAS) to more sophisticated sand control methods, such as gravel packing. For multilateral wells in this region, even though gravel packs have been installed in other regions, developments to date have been limited to oil producers with SAS with inflow control devices (ICDs) and swell packers for compartmentalization. Nonetheless, the process of constructing and completing a subsea multilateral completion can be complex, and often trip intensive. Early multilateral field developments borrowed technology from the Norwegian northwest shelf; however, as such, the completions were not optimized for the specific Australian operating environment. Following the first successful subsea multilateral field developments in Australia, customized technology began to be developed to address and improve completion efficiencies. Specifically, several global and regional first installations were implemented between 2014 and 2016 that reduced dedicated installation time by 42% and helped reduce or eliminate operational risks.

In addition to discrete technologies, well architectures have also been revisited to further the economic advantages of multilateral completions. Trilateral wells, where three laterals penetrate the reservoir, are now commonplace in subsea developments in Australia. The custom solutions developed throughout the past 10 years demonstrate not only industry maturity, but also region specific advancements in multilateral completion technology.

Australia's history of multilateral completions is a success story, highlighting an industry's adoption of new technology and appetite for improvement on a broader scale. In ten years, the step change in multilateral completion has been appreciable. The result of a decade worth of improvement and customization is a fit-for-purpose, reliable, robust and efficient completion practice.
Effect of Kerogen Type and Maturity on Performance of Carbon Dioxide Storage in Shale
Authors: Takbiri-Borujeni Ali , Kazemi Mohammad , Sun Ting , Mansouri-Boroujeni Mahdi
Published: October 2017

Potential for sequestration of carbon dioxide in organic rich shale is investigated in this work. Adsorption isotherms and Onsager diffusion coefficients are determined using molecular dynamics simulations for atomistic kerogen models. The kerogen unit models prepared by (Ungerer et al., 2014) are used in this study. To build representative solid state models for kerogen, eight kerogen molecules are placed in a periodic cubic cell. Once the initial configuration of kerogen molecules is prepared, constant-temperature constant- volume simulations and then constant-temperature constant-pressure simulations are performed to obtain the final structures. For the final structure, computed density and adsorption isotherms are within the reported experimental values. Grand Canonical Monte Carlo (GCMC) simulations are performed for CH4-CO2 mixtures to investigate binary adsorption isotherms in kerogen models with different maturities. Equilibrium molecular dynamics (EMD) simulations are used to determine Onsager diffusion coefficients. As pressure for each species in the binary mixtures increases, its adsorbed amount increases and adsorbed amount of the other species decreases. Adsorbed amount of CO2 is higher than that of CH4 for all kerogen types at all pressures tested due to the strong permanent quadrapole moment of CO2. Due to higher adsorption affinity of CO2 to kerogen pore surfaces compared to CH4, its Onsager diffusion coefficients are smaller than those for CH4 for all kerogen types.
Further Insights into the Mechanism of Disproportionate Permeability Reduction
Authors: Liang Bin , Jiang Hanqiao , Li Junjian , Seright R. S. , Lake Larry W.
Published: October 2017

Disproportionate permeability reduction (DPR) is a phenomenon whereby many water-soluble polymer solution and polymer gels reduce the permeability to water flow more than to oil or gas flow. DPR is important for some gels that are applied to production wells in water-shutoff treatments. The mechanisms of DPR need more investigation and clarification. In this study, experiments on two different scales, core- and micro-model-scale, were conducted to study the mechanism of DPR in flow through permeable medium treated with Cr(III)-acetate-HPAM gels. The procedures for the two experiments can be similarly divided into five phases: gelant injection and gelation, oil flooding, gel rehydration with no oil phase pressure difference, oil re-flooding, and water flooding.

In the core-scale experiments, we used nuclear magnetic resonance (NMR) to monitor the T2 signal change during fluorine-tagged oil and water flooding after the gel treatment. NMR can detect the signal change of trapped and free water inside the gel in different pore sizes in porous medium. In the micro-model-scale experiments, a microscopic glass-etched model is subject to red oil and blue water flooding alternately after the gel treatment. Oil extrusion under an oil phase pressure gradient and the evolution of oil flow channel are recorded by a video sensor. The subsequent water flooding is also investigated.

Results show that a gel-displacement mechanism is a primary reason for the development of the oil flow path initially. As the displacement proceeds, the gel dehydration occurs induced by the oil phase pressure and therefore the flow channel continues forming, but no gel is produced during this phase. During gel rehydration, the flow channel is blocked, which can be inferred from the T2 spectrum and visual microscope image. However, the rehydrated gel can only partially reduce permeability and oil pathways re-establish easily with the subsequent oil flooding. In water flooding, water permeability decreases abruptly. The mechanisms for the disproportionate permeability reduction involve channel segregation, gel rehydration, residual oil effects, and the low permeability of gel relative to water.
Stress Management: First Openhole Multistage Ball Drop in Khazzan
Authors: Casero A. , Rylance M. , Al Shueili A. , Ishteiwy O. , White D. , Al Manji A. , Dawson W. , dwi Kurniadi S. , Bruseth E.
Published: October 2017

Openhole multistage (OHMS) completion systems have been available for nearly 20 years. Their introduction was primarily linked to improved operational efficiency, achievable through the elimination of redundant operations, costs, and time from the existing application of plug-and-perf (P&P) solutions. However, increased understanding with time has demonstrated that the most effective applications of the approach are those that offer better connection within the reservoir. Examples of such applications include delivery of fracturing within extended reach wells, application to naturally fractured formations, and use of the OHMS systems in offshore or logistically challenged areas.

The use of an OHMS system has a number of potential advantages for certain applications, not least of which is preservation of the uncemented annulus with extensive direct reservoir access within the completion. One of the major advantages of this geometry is that there is an unparalleled and flawless wellbore-to-reservoir communication in place, immediately prior to fracturing. In hard-rock, high-stress-ratio cased-cemented scenarios, where tortuosity and near-wellbore friction can dominate, an ability to avoid such issues in the first place is an advantage. This is particularly true in those horizontal wells drilled and completed in complex stress regimes. In these cases, a complex connection resulting from perforating can often be detrimental to creation of desired fracture width, making proppant placement challenging and thereby reducing the effective fracture conductivity.

Within the Khazzan field, in the Sultanate of Oman, such a complex tectonically impacted stress-state exists in the formations of interest, combined with an ancient hard-rock environment exhibiting a wide variance in effective permeability. Early multifractured cased-cemented horizontal well simmediately demonstrated complex fracture-to-wellbore communication behaviour, which was addressed in a number of ways. One of these approaches included plans for deployment of the OHMS as a potential technique to ensure a smoother and simplerfracture-to-wellbore interface.

This paper will fully describe the experience of the first OHMS completion deployed in the Khazzan field including details on the fracture design, operational execution, surveillance, post-fracture cleanup, and productivity. The paper will particularly address those aspects related to near-wellbore tortuosity, fracture connectivity, proppant placement, and evidence of connection quality. The paper will assess this completion approach alongside previously applied techniques and report on the potential of the approach for more widespread deployment in resolving fracture complexity.
Proppant Transport in Fractures with Foam-Based Fracturing Fluids
Authors: Tong Songyang , Singh Robin , Mohanty Kishore K.
Published: October 2017

The placement of proppants in hydraulically fractured wells determines the conductivity of fractures and productivity of shale wells. In slickwater farcturing, proppants are often not transported deep into fractures. In this paper, proppant transport in foam-based fracturing fluid is visualized in a laboratory-scale fracture slot. Effect of parameters like foam quality, proppant loading, and injection rate are systematically investigated. Additionally, a CFD based model is developed to simulate the lab experiments by assuming the foam as a single-phase non-Newtonian fluid. Experiments show that dry foams (80% quality) can carry proppants between the lamellas with little vertical settling. A complex flow pattern is developed at the bottom of the slots in dry foams due to protrusion of foam fingers into proppant laden foam flow. Proppants are not carried very well in wet foams (70% quality) and form a proppant bed near the injection well. This is due to severe drainage of surfactant solution from the foam as it moves through the fracture. CFD simulation of proppant transport agrees approximately with the experimental observations for the dry foams. The simulation results do not agree with the experimental observations for the wet foams. The assumption of treating foams as a continuum non-Newtonian fluid is not valid for wet foams where drainage of surfactant solution is significant.
Rock-On-A-Chip Approach Provides New Insight for Well Interferences in Liquids-Rich Shale Plays
Authors: He Kai , Xu Liang , Lord Paul , Lozano Martin , Kenzhekhanov Shaken , Yin Xiaolong , Neeves Keith , Huang Tao
Published: October 2017

As infill drilling practices become more widely used, operators have observed increased well interference or "bashing" in various shale plays wherein the production of mature wells has been significantly impaired by new infilling wells. Notably, some wells have experienced production decrease of approximately 80% as a result of bashing. One possible explanation is the occurrence of hydraulic communication between the old and new wells because they are most likely connected by the newly created or reactivated natural fractures. However, the mechanisms in which hydraulic communication influences production have not been fundamentally studied.

Current technologies, such as pressure-transient analysis or production data mining, do not explicitly provide a physical understanding of the bashing phenomena. This paper discusses a study wherein "Rock-on-a-chip" (ROC) devices were used to investigate hydraulic fracturing fluid invasion and flowback processes. A homogeneous porous network based on the Voronoi tessellation method was patterned on a ROC device. To simulate one aspect of well interference (the impact of an offset well's fracturing fluid entering an existing well's fracture network), two fluid invasion-flowback cycles were performed. It was hypothesized that if the fracturing fluid injected through the new infill enters the fracture networks of existing wells, fracturing fluid would again be forced into the matrix, inflicting damage to the fracture-matrix interface and impairing production.

Test results revealed that water saturations in the ROC after the second flowback were higher than those after the first invasion-flowback cycle, suggesting that the second invasion-flowback cycle could indeed damage the matrix and reduce the relative permeability of the oil. Additionally, surfactant clearly improved the displacement efficiencies in the matrix. One experiment shows that surfactant used in the second invasion-flowback cycle even reduced the damage incurred by the first invasion-flowback cycle. The benefit of surfactant has been observed from field results from the Wolfcamp shale, where it was discovered that the EURs (estimated ultimate recoverys) of wells bashed by surfactant-stimulated offset wells were higher than those bashed by non-surfactant-stimulated offset wells. This study shows that fracturing fluid from offset wells can, in fact, damage the productivity of existing wells through connected fractures. In addition, surfactant, when properly selected, can potentially be used to help reduce damage, or even repair previous damage, caused by well bashing.
Automated Mud Logging System as a Cost-Efficient Way of Acquiring Subsurface Data: Results of the Field Trial
Authors: Nikitin Anton , Krugliak Zinovy , Stepanov Vitaly , Dolan Sean
Published: October 2017

In this paper, we present a new surface logging technology, named the Automated Mud Logging System (AMLS), which is a cost-effective alternative to advanced wireline logging required to identify producible oil in tight rocks.

AMLS provides characterization of drill cuttings samples at the well site. Current version of the system (AMLS ver 1.0) includes a Natural Gamma-ray Spectrometer (NGS) and Nuclear Magnetic Resonace (NMR) relaxometer, with an automated sample feeding system which can be installed in a mud logging unit to perform sample analysis while drilling. The sensitivity of NGS and NMR measurements to sample volume avoids time consuming and labor intensive sample preparation required by other geological material characterization methods (e.g. X-ray diffraction, X-ray fluorescence, etc.) which are surface sensitive. The ability of NGS and NMR to characterize "as received" cuttings allows for the automation of data acquisition and minimizes the operational expenses.

Results from a field trial of AMLS on a vertical well, drilled through tight formation at a rate of penetration (ROP) of approx. 120 ft/hour are also presented. The uranium (U) concentration curve from cuttings, acquired by the AMLS ver 1.0, compares favorably with that acquired by a wireline tool. This demonstrates the robustness of the developed system to characterize drill cuttings for formation evaluation. The main challenge in cuttings analysis is ensuring efficient mud logging operations at the well site during fast drilling (e.g. sampling cuttings every 5 ft in depth with a ROP of 100-120 ft/hr)

The presented results demonstrate the feasibility of converting mud logging from a source of qualitative information about the subsurface into a source of quantitative information comparable to the information delivered by wireline or LWD logging but acquired at much lower cost and operational risk. The addition of other components to AMLS such as automated sample catcher and Neutron Induced Gamma-ray Spectroscopy (NIGS) measurement system should make this mud logging system even more valuable source of subsurface information. Another enhancement of the data acquired by AMLS can originate from properly acquired advanced mud gas logs. An example of the application of data acquired by NGS node of AMLS ver 1.0 and mass spectroscopy-based mud gas logging system to identify intervals containing producible oil in a tight rock formation in West Texas, is presented.
Reducing BOP Testing Costs During Wireline Logging Campaigns
Authors: Stroud J. , Basu R.
Published: October 2017

During a wireline logging campaign on exploration wells, function testing a Blow Out Preventer (BOP) happens every 7 days per regulations. This test can take 12 to 24 hours and result in 1 to 1.5 days of rig downtime. The authors have internally developed a method of reducing the time of test to approximately 10 hours or less through novel invention. This paper intends to release the intellectual property of said invention into the public domain.

The current practice of executing BOP Functional Tests involve tripping down standard drill pipe to the BOP. If the operator is in the process of running a log, that means putting the process on hold and running back down with pipe. The BOP Function Test Bar (Bftb) is a tool capable of being attached to wireline which allows the function test of a BOP without tripping pipe. This method is conceived as a cost-saving and safer alternative.

The Bftb is a newly developed and patented wireline conveyed device that can be used to function test the BOP significantly faster and safer than the traditional pipe-in pipe-out method. The Bftb-Gen1 was qualified for sub-sea operations and piloted on Nobel Globetrotter-1 in the GOM after an 8-month development process in 2015. The Bftb –Gen 2 tool with increased utility to allow BOP pressure testing capability was deployed in early 2017. Conveying the Bftb directly on the wireline improves HSSE and reduces the time required to conduct the BOP function test by ~10 hours, resulting in significantly less rig down time. The entire R&D investment was recovered in the initial pilot, and there stands to gain annual OPEX savings in the millions, based on 4-8 deployments a year.

This paper will present both the technical specifications and operational implementation of Bftb for the audience's use. Additionally, the results of both deployments will be available to compare with the forecasted value proposition. There overall desire is to share the lessons learned with industry and allow the market to determine the adoption rate and further development of the Bftb.
Transient Operations and Instabilities in Different Production Scenarios: Modeling and Validation
Authors: Almudairis Fahad , Zhang Hong-Quan
Published: October 2017

This study presents a unified transient model that can be used as a tool to predict different transient multiphase flow phenomena in petroleum production and transportation through wells and pipelines. These transient behaviors such as production rate change, sudden perturbation of steady state flow or cyclic flow behavior are predicted and analyzed. For cyclic flow behaviors, the casing heading instability that occurs in gas-lift operations are investigated. The development of the model is based on mass and momentum conservation equations. A transient heat transfer model is also developed to estimate the temperature profile along the production system. The black oilmodel is added to calculate the fluid properties at each time step.Several methods were developed in the past to predict flow instabilities. However, they are designed for specific transient behavior and they can only predict whether or not the flow is unstable. They cannot quantify how unstable it will be. The present model can predict the detailed multiphase flow hydrodynamic behaviors including pressure, temperature, local flow pattern, liquid holdup, and fluid velocities. The model is validated through comparisons with experimental results and field data.
Relative Permeability and Residual Saturation Estimates for Organic-Rich Shale Samples From Bakken, Wolfcamp, Eagle Ford and Woodford Formations
Authors: Ojha Shiv Prakash , Misra Siddharth , Sinha Ankita , Dang Son , Tinni Ali , Sondergeld Carl , Rai Chandra
Published: October 2017

Relative permeability and residual saturations of organic-rich samples were determined from low-pressure nitrogen adsorption-desorption measurements on the samples. Robustness of this relatively new estimation technique for shale-reservoir samples is evaluated in this study. Petrophysical correlations of relative permeability and residual saturations with kerogen maturity, kerogen content, kerogen removal, and sample cleaning are developed for purposes of improved understanding of the saturation-dependent transport behavior of shale reservoirs. These correlations enable comparative predictions of intra-well and inter-well production performances.

Adsorption-desorption isotherm measurements were performed on 100 organic-rich shale samples from Bakken, Wolfcamp, Eagle Ford and Woodford formations. Total organic content varied in the range of 1 to 9 wt.% and the porosity varied in the range of 1 to 10 %. The adsorption-desorption measurements were interpreted to obtain pore size distribution (PSD) using a modified Barrett-Joyner-Halenda method. Bimodal fractal model was then applied to the PSD estimates to compute certain percolation and fractal parameters, which were implemented into percolation theory, effective medium theory and critical path analysis models to generate the relative permeability curves and residual saturations of the 100 samples.

Kerogen maturity was found to be the dominant factor affecting the relative permeability and residual saturation estimates. Irreducible water saturation and residual hydrocarbon saturation estimates increased from 30% to 60% and 20% to 40%, respectively, with an increase in kerogen maturity from oil window to late-condensate window. This implies a sharper decline in hydrocarbon rates (lower cumulative hydrocarbon production) and a prolonged period with lower water rates (lower cumulative water production) for shale reservoirs with higher kerogen maturity. Estimates of relative permeability of hydrocarbon and aqueous phases at 80% saturation of the corresponding phases increased from 0.7 to 0.75 and 0.05 to 0.2, respectively, with the decrease in kerogen maturity. This can be explained by decrease in relative contribution of micropores to total porosity with decrease in kerogen maturity. Higher mean pore size for samples with lower thermal maturity leads to better saturation-dependent transport properties in these samples. When the samples were cleaned with toluene-methanol mixture to remove soluble, dead hydrocarbons and bitumen from the samples, the hydrocarbon phase residual saturation estimates decreased by 20%, whereas the aqueous phase irreducible saturation estimates increased by 9%. Simultaneously, cleaning resulted in decrease in wetting phase relative permeability with increase in non-wetting phase relative permeability.
Comparison of PR-EOS with Capillary Pressure Model with Engineering Density Functional Theory on Describing the Phase Behavior of Confined Hydrocarbons
Authors: Liu Yueliang , Jin Zhehui , Andy Li Huazhou
Published: October 2017

Peng-Robinson equation of state (PR-EOS) with capillary effect has been extensively used to describe the phase behavior of hydrocarbons under nano-confinement in shale reservoirs. In nanopores, surface adsorption may be significant and molecular distribution is heterogeneous. While PR-EOS cannot take into account these effects, statistical thermodynamic approaches such as density functional theory (DFT) can explicitly consider the intermolecular and fluid-surface interactions. In this work, we compare the phase behavior of pure hydrocarbons and mixtures in nanopores from PR-EOS with capillary effect and engineering DFT. We apply the Young-Laplace (YL) equation assuming zero contact angle to calculate the capillary pressure in PR-EOS with capillary effect. On the other hand, we extend the PR-EOS to inhomogeneous conditions by using weighted density approximation (WDA) in engineering DFT.

For pure components, both approaches predict that the dew-point temperature increases in hydrocarbon-wet nanopores. While engineering DFT predicts that the confined dew-point temperature approaches bulk saturation point when pore size approaches 20 nm, the saturation point obtained from PR-EOS with capillary effect approaches bulk only when the pore size is as large as 1 μm. With engineering DFT, the critical points in nanopores deviate from that in bulk, but no change is observed from PR-EOS with capillary effect model. The difference between PR-EOS with capillary effect and engineering DFT on the dew-point temperature decreases as the system pressure approaches the critical pressure. At low pressure conditions, PR-EOS with capillary effect model becomes unreliable.

For binary mixtures, both approaches predict that the lower dew-point decreases and the upper dew-point increases. More interestingly, phase transition can still occur when the system temperature is higher than the bulk cricondentherm point. Engineering DFT predict that the confined lower dew-point approaches bulk when pore size approaches 20 nm, whereas the dew-point obtained from PR-EOS with capillary effect approaches bulk only when the pore size is as large as 100 nm. This work illustrates that assuming homogeneous distributions in nanopores may not be applicable to predict the phase behavior of hydrocarbons under nano-confinement.
API RP 19B Section 2 Perforation Tests Conducted at Multiple Facilities to Guide the Latest Section 2 Revision
Authors: Ayre David , Atwood David , Geerts Shaun , Grove Brenden , Haggerty Dennis , Hardesty John , Lattanzio Dario , McNelis Liam , Sampson Tim , Sokolove Chris
Published: October 2017

The results of API RP 19B Section 2 tests conducted at eight charge manufacturer's testing facilities were used to determine whether differences in vessel size and configuration resulted in different depth-of-penetration results. Findings from these round-robin tests were also used to help guide changes to the newly revised Section 2 documentrecently voted on, approved, and currently in review by API.

After agreement among the eight companies was reached on the testing specifics, the tests were conducted over a period of time, enabling an independent operator to observe the tests at each facility. A batch of quality, deep-penetrating shaped charge was supplied by a single manufacturer, and the rock targets were sourced from the same block to minimize differences and allow for fair evaluation of the different testing systems. The hardware materials and test configurations used in the tests were specified (scallop plate and casing coupon, wellbore and target pore pressures), and the independent operator verified that each test was conducted accordingly. The independent operator tabulated the penetration-depth and casing-hole-size data from the tests for comparison per Section 2 testing specifications.

At each testing site, a set of successfully performed tests was conducted at confining stresses of 1,500, 3,500, 6,500, and 9,500 psi. The resulting penetration depths were all plotted versus confining stress on the same chart. A statistically significant correlation was found between penetration depth and confining stress (as expected); with a minor correlation with porosity. Most of the scatter in the data was observed at confining stresses of 1,500 and 3,500 psi. A statistical analysis showed that the diameter of the core (4, 5.25, and 7 in.) did not influence the penetration results for this particular deep-penetrating, 21-g explosive shaped charge. This knowledge enables a testing company to conduct Section 2 tests at a lower cost. Additionally, based on statistical analysis, the option of housing the shaped charge within the wellbore chamber versus an open-style configuration is valid because it did not affect the penetration results. The information and results collected from the eight different facilities provide options for vessel type and system configuration and also suggestthe variance to expect in Section 2 tests. Insight into the methods used for conducting these tests and background information on handling the cores are included.
Real Time Cement Displacement Tracking using Distributed Fiber Optic Sensors
Authors: Wu Qian , Dininger Marjorie , Nair Sriramya , van Oort Eric , Guzik Artur , Kishida Kinzo
Published: October 2017

Cement displacement efficiency significantly affects the quality of a well cementing job. Inefficient displacement of drilling fluids by spacers and cement slurry results in poor placement and potential contamination of the cement, which in turn can compromise cement integrity and threaten zonal isolation of oil and gas wells. In this paper, a novel method is introduced to monitor the cement displacement process in real time using fiber optic distributed temperature and strain sensing (DTSS) technologyas drilling fluid, spacer and cement are pumped through the casing annuli.An advanced DTSS system, based on hybrid Brillouin and Rayleigh backscattering, was used in combination with a specially designed fiber optic cable to identify the location of each fluid (i.e. drilling fluid, spacer fluid and cement slurry) during the cement displacement process. The fiber optic cable consists of a single-mode optical fiber packaged with a polymer that has selective sensitivity to various well construction fluids, and thus can be used to detect the presence of each fluid. Both strain and temperature changes were monitored by the DTSS system to track the cement displacement process. When the proposed fiber optic cable was exposed to synthetic-based mud (SBM) and spacer fluid, the strain values recorded by the fiber differed by a few orders of magnitude. When the cable is exposed to cement slurry, the location of cement can be determined from its exothermic heat release signature, which is apparent in both strain and temperature measurements. Contamination of cement slurry with drilling fluid was found to have a significant impact on the strain and temperature profiles. Thus, the DTSS system can provide useful information regarding top of cement (TOC), the wait-on-cement (WOC) time and the displacement efficiency in real time. Cement displacement of drilling fluids and spacer fluids has been modeled in the past; however, to date the displacement process and the locations of these fluids have never been tracked and verified in real time. This paper presents a new way for real-time, in-situ, continuous, and non-disruptive monitoring of the cement displacement process and tracking of the well construction fluids.
Novel Use of Application-Specific Integrated Circuits in Quartz-Based Permanent Downhole Gauges Increases Reliability Estimates in High-Temperature Applications
Authors: Zheng Quanling , Garcia Elias , Balasubramanian Aswin
Published: October 2017

This paper demonstrates the benefits of using application-specific integrated circuits (ASICs) in the design for downhole, quartz-based, pressure and temperature permanent downhole gauges (PDGs).

Historically, downhole electronics have been built with general purpose chipsets, whose functions areadapted to suit design needs. In contrast, through integrating and optimizing the necessary functions into a single integrated circuit (IC), ASIC technology enables a chipset to be customized for a particular use. Compared to the previous generation of PDGs, this approach reduces the overall footprint of the gaugeand improvesthe overall gauge performance,especially for reliability performance. Suchimproved reliability performance is validated through the use of the design for reliability (DFR) process, which consists of define, identify, verify, and validate stages. Thecoreof the validate stage is thereliability demonstration test (RDT).

The detailed advantages of the novel use of ASIC technology in PDGs are discussed in this paper, with comparison to the previous generation of PDGs. The incorporation of ASIC circuitry enables lower current consumption, which in turn enables deployment of an increased quantity of pressure and temperature PDGs without increasing the system's power budget. The implementation of ASIC technology helps reduce the overall size of the PDGs, with a 67% reduction in length and a 44% reduction in outer diameter (OD), which also enables direct integration to tubing encased conductors (TEC) by means of prewelded and prespooled connections.The RDT results demonstrate that the ASIC-based PDGcan at least triple the operationlifetimecompared to the previous generation of PDGsin high-temperature downhole environments.

Overall, the adoption of ASIC technologysignificantly improves the reliability of PDGs, demonstrating a life of 10 years at 175°C with 80% reliability and 60% confidence in accordance with industry recommended practices, andprovides a permanent downhole monitoring system with a deployment of 40 or more gauges for high-pressure/high-temperature (HP/HT) applications.
Multi-Scale Fluid Phase Behavior Simulation in Shale Reservoirs by a Pore-Size-Dependent Equation of State
Authors: Luo Sheng , Lutkenhaus Jodie L. , Nasrabadi Hadi
Published: October 2017

The phase behavior of reservoir fluids plays a fundamental role in predicting well performance and ultimate recovery. Currently, the uncertainty in phase behavior is one of the greatest challenges in developing unconventional shale resources. The complex phase behavior is attributed to the broad range of pore sizes in shale. In macro-scale geometries such as fractures and macropores, the fluid behavior is bulk-like; in nano-scale pores, the fluid behavior is significantly altered by confinement effects. The overall phase behavior of fluids in porous media of mixed pore sizes is yet to be understood.

In this paper, we present a multi-scale fluid phase behavior study. A pore-size-dependent equation of state (EOS) is used to describe the fluid by the confining pore diameter. The EOS confinement parameters for fluid-pore wall surface interaction are determined by experimental results from differential scanning calorimetry and isothermal adsorption of species C1~C14. The multi-scale phase equilibria are simulated by directly minimizing the total Helmholtz free energy. A modified Eagle Ford oil is used for the case study. Constant composition expansions (CCE) of dual-scale (bulk and 15 nm) and triple-scale (bulk, 15 nm, and 5 nm) systems are simulated. The first bubble emerges from the bulk region at a lightly suppressed "apparent" bubble point pressure. Below the bubble point, the liquid saturation in the bulk region drops sharply, but the fluids in the nanopores are undersaturated throughout the multi-stage expansions. In the end, large amounts of intermediate to heavy hydrocarbons are retained in nanopores, implying a significant oil recovery loss in shale. The confinement effect also leads to near-critical phase behavior in small-scalenanopores (<5 nm).
A Resource-Oriented Method of Oily Sludge Disposal in ASP Flooding Production
Authors: Wang Zhihua , Rui Zhenhua , Lin Xinyu , Xu Mengmeng , Bai Ye , Luo Jiaqi
Published: October 2017

In the field practice of alkaline/surfactant/polymer (ASP) flooding, there is more oily sludge produced and accumulated in settling tank, dehydrater, recycling pool, etc. Timely and effective disposal of oily sludge has already played an indispensable role in establishing the surface and subsurface integration pattern with chemicals EOR. Many conventional disposal methods faced to the challenges of separation efficiency, facilities pollution, healthy and environmental threats, and economical justification with the appearance of alkali, surfactant and polymer in produced liquid (mixture of oil and water of wells). We focus on using physical comprehensive effects to remove the emulsified oil and absorbed water, and the in-situ utilization of the left sludge was regarded as a method development to address the challenges recently. A laboratory investigation of characterizing the properties of oily sludge in ASP flooding production was recently carried out. The heating-washing-centrifuging combination treatment process was practiced. After removing its emulsified oil and absorbed water, the sludge transported to filter bed to form a suspended sludge blanket was studied and the feasibility of in-situ utilization of filtering separated water was also evaluated. The application effects of the resource-oriented disposal method were assessed, and the integration technology and operation parameters were designed and optimized.

The results indicate that the oily sludge with ASP flooding is characterized by high caloric value, high water cut, high viscosity, strong electronegativity and stability, and there is relatively high melting temperature, more wax and asphaltenes in oil phase. There appears to be a linear relationship between the scale of oily sludge deposition in surface facilities and the appearance concentration of chemicals in produced liquid of production wells. Compared with the previous thermochemistry demulsification disposal methods, dirty oil recovery ratio increased more than 15%, and running expense was reduced around 20%. The dirty oil content in the sludge was less than 2% when disposed under the combination disposal process and operation parameters. Furthermore, the formed suspended sludge blanket has the functions of in-situ purification of separated water, achieving the cyclic utilization in washing process. The probable impacts of its direct discharge into the normal sewage treatment system reduced and secondary pollution decreased spontaneously. This study is beneficial to provide a robust and potential way for disposing oily sludge in the production and operation of chemicals EOR, and it is also significant to understand the surface and subsurface integration idea and further accelerating ASP flooding application in high water cut oilfields.
Novel Application of Elemental Aluminum and Zinc to Generate aSelf-Compressing Silicate System for Use in Lost Circulation and Conformance
Authors: Soucy Kelly , Cramer Brett , McDonald Michael , Li Xianglian
Published: October 2017

Effective zonal isolation is critical in lost circulation, cement repair and conformance applications. To be successful it is often necessary to not only block pathways but also ensure a tight seal. Gaps or weak points between the blocking material and boundary layers can result in poor zonal isolation leading to gas migration, gas entrapment, and/or excessive water production among other issues. The mechanisms vary but cement, polymers, and sodium silicate can all lose volume upon setting and aging. The degree of contraction being impacted by downhole events such as fluid loss, influx of gas, water or conditions such as high temperatures

In the case of Portland cement, several different methods have been developed to ensure dimensional stability. A long time approach has been the addition of aluminum powder to the cement slurry for the in-situ generation of hydrogen gas. This paper looks at how elemental aluminum as well as zinc can be adapted for use in a sodium silicate-based system. In developing a new technology, several questions are posed at the onset. At the top of this list are the health, safety, and environmental implications of the individual components and final product. Fine powders are inherently dusty and carry an explosive risk if not properly handled. Development of a safe form of the metal powders became the first priority. The direction taken was to slurry the metals using suitable base oils and mutual solvents. As part of the slurry development, the shape and size of the aluminum and zinc were studied for resistance to settling, rheological stability, and reaction kinetics.

Stable metal slurries could be formed in base oils such as polyalphaolefins or mineral oils when combined with other additives. The selected base oils were shown to function in a similar manner as encapsulators and be used control the rate of the gas generation reaction. Mutual solvents such as triacetin provided further functionality by being able to initiate a polymerization reaction of alkali silicate. Short-term properties such as set time, density, rheology, and compressive strength were made adjustable by concentration and the use of filler/bridging material such as walnut hulls, glass powder, calcium carbonate, barite, or fly ash.

While sodium silicates can be set by either an internal or external setting agent, the industry preference is for a one component system. Presented in this paper will be the development of a one component system that safely incorporates the in-situ generation of hydrogen to yield a chemically durable, mechanically strong expanded silicate-based plug.
Streamline Rock Facies Classification with Deep Learning Cognitive Process
Authors: Mohamed Sidahmed , Roy Atish , Sayed Anjum
Published: October 2017

Hydrocarbon resource identification process involves significant endeavors and persistent efforts to identify sweet spots and economical discoveries. To help streamline the process and better support subsurface teams, a suite of machine learning models have been piloted for integration into the workflow. This paper introduces a sub-process of classification models for automatic prediction of reservoir rock facies types based on acquired sample well logs.

We present results from a synthesized dataset based on a formation with a series of different stacked reservoir rock types. The main reservoir is further sub-divided into four sections.

Our method is based on cognitive deep structures, where more complex facies attributes are inferred from lower level raw features. The algorithm mimics biological brain hierarchical order for recognizing patterns/objects. The incremental learning process iteratively improves on facies identification as new evidence is introduced to the machine learner. We train the model on a small sample of well log attributes and validate performance on excluded wells.

The model performs relatively well on a limited training sample. In a typical field development process, only a few appraisal wells are available for explorers to determine resources location and juxtaposition. Results show that distinction between good quality homogenous to parallel or cross-bedded rock from poor quality clay rich laminated facies is well predicted. This is an important step forward, as it helps geologists and geophysicists re-affirm conclusions about best, good, and poor quality rock type locations. The integration of deep learning models into the appraisal process provides an additional assessment lens and helps accelerate full field development of the resource.

This paper introduces an enhanced capability for intelligent classification of reservoir facies based on well log attributes. The cognitive deep learning sub-system has the advantage of self-adaptability as more samples become available. Our approach yield superior results relative to the best outcome of an industry collaborative facies prediction using machine learning, and is a demonstration of the potential of emerging digital capabilities for Upstream workflows.
A Novel Networked Check Point System Keeps Track of Human and Vehicle Flow in and out of Oilfield Locations
Authors: Haci Marc , Quezada Arturo
Published: October 2017

A new networked check point tower system has been designed specifically for remote oilfield work sites. The system keeps track of human and vehicle flow providing an accurate headcount of who is on location at any given time. The check point tower enhances operational safety and aids in enforcing compliance with company policies.

Automated and networked check point tower(s) can watch over an area of interest and allow workers to check-in and check-out with their unique remote RF devices. The new approach is a considerable step up from sometimes employed manned gate guards with a clipboard or a sign-up sheet at the rig manager's door. A set of cameras and sensors are packaged in a light, portable tower that can quickly move with the drilling rigs or completion crews or be deployed on unattended locations. Towers upload events data continuously to a central server and such data is monitored 24/7/365 and available to clients as interactive analytics reports. Flexibility allows deployment of a single tower or multiple towers in fields of varied complexity and synchronized to account for traffic entry and exit from multiple directions.

Development and design criteria of the check point towers are explained in this paper. The system of towers is easily deployed in attended drilling and completion locations as well as unattended production locations. Case histories show accurate personnel head count positively impacts operational safety. Presence of check points discourage theft and encourage personnel productivity in unsupervised locations.

This paper introduces a novel tool that just become available in the oilfields that finally enhances counts and records who is on location decades after the industry begun to add to the digital oilfield hundreds of operational parameters such as pressure, flow rate, block height, or trip speed.