bluuebunny/crossref_metadata_2025 huggingface dataset:
Quality Control of NMR Measurements in Unconventional Rocks Using Hilbert Transforms and Semi-Logarithmic Derivatives
Authors: Aérens Pierre , Medellin David , Torres-Verdín Carlos
Published: October 2020

Nuclear magnetic resonance (NMR) measurements are extremely valuable in the assessment of fluid-flow properties of rocks. However, inverted transverse-relaxation time (T2) distributions are often biased by positivity constraints and the regularization method. In some cases, it is difficult to determine whether the estimated pore-size distributions are correct or by-products of the inversion. On-site quality-control of inversion results is thus essential to avoid erroneous analyses based on non-physical results across unconventional rocks.

We introduce and compare two quality-control approaches based on two different signal processing practices: the semi-logarithmic derivative and the Hilbert transform. Validation of the inverted T2 distribution is performed by applying either processing method to the echo train decay of proton magnetization to estimate a pseudo-T2 distribution that is not affected by inversion artifacts. These two methods are data-driven processes for on-site, continuous quality control of borehole NMR measurements. In the first method, a pseudo-T2 distribution is constructed by taking the derivative of the echo train decay with respect to the natural logarithm of the relaxation time. For the second method, the Hilbert transform is applied to the raw proton magnetization decay to approximate the T2 distribution.

NMR laboratory measurements were performed on a wide variety of rocks, the associated T2 distributions were estimated using linear inversion and the two quality-control methods were applied to the same data. The reliability of our quality-control procedures was verified by benchmarking them against the inverted T2 distributions. Furthermore, these quality-control methods, when applied continuously to borehole NMR measurements, enable the optimization of the measurements in real-time to mitigate biased noise. By verifying the location of the dominant mode of the T2 distribution, the NMR operator can determine whether more stacking of proton magnetization decays is needed to attain a high-quality estimation of the pore-size distribution before performing the T2 inversion.

Our work provides the basis of effective quality-control methods for NMR measurements for the petrophysical interpretation of rocks with complex pore-size distributions, especially in unconventional rocks, where noise present in the measurements, especially at early acquisition times, can completely mask the useful signal originating from pore-size distributions and fluids. The fast and reliable quality control of estimated T2 distributions is not affected by inversion artifacts, relying only on unfiltered, raw data.
Microfluidic and Numerical Investigation of Trapped Oil Mobilization with Hydrophilic Magnetic Nanoparticles
Authors: Wang Ningyu , Liu Yifei , Cha Luming , Prodanovic Maša , Balhoff Matthew
Published: October 2020

Nanoparticles have great potential to mobilize trapped oil in reservoirs by reducing the oil-water interfacial tension, altering the rock wettability, stabilizing foams and emulsions, and heating the reservoir to decrease the oil viscosity. However, the direct application of magnetic forces on paramagnetic nanoparticles in reservoir engineering applications has not be extensively investigated. We demonstrate the enhanced oil recovery (EOR) potential of hydrophilic magnetic nanoparticles in oil production by direct observation using microfluidics.

We studied the mobilization of oil blobs by a ferrofluid (a suspension of hydrophilic magnetic nanoparticles in water) in a converging-diverging channel with varying depth (so-called 2.5D micromodel). The channel had a varying depth of 10-30 microns and a varying width of 50-200 microns, approximating a flow path in the rock. The nanoparticle suspension was injected at 0.1 microliter/hour. The channel was made of glass and thus the water-based ferrofluid was the wetting fluid.

Initial ferrofluid flooding experiments were performed under a static magnetic field. This magnetic field caused oil droplet deformation, dynamic break-up into smaller droplets, and subsequent residual oil saturation reduction. Significant oil blob displacement was observed within 2 hours after the magnetic field was applied. During the flooding, the oil saturation within the observation area of the micromodel reduced from 27.4% to 12.0%. We then hypothesized that a changing field would have an even larger effect in saturation reduction. We have thus designed experiments with a magnetic field of the same magnitude slowly rotating under the micromodel. We subsequently observed a completely different phenomenon, namely self-assembly of oil droplets, indicating formation of the hydrophilic magnetic nanoparticles microstructures (chains under the magnetic field). These magnetic nanoparticle microstructures were ever-changing under the rotating magnetic field. While the ability of ferrofluid to rotate small blobs was in itself interesting, in experiments without actual flooding (and thus synergy of hydrodynamic and magnetic forces) we did not observe any additional oil recovery.
Preventing the Next Big Well Control Event – A Leading Indicators Approach
Authors: Tamim Nafiz , Karlsen Geir , van Loopik Geert , Pettigrew James
Published: October 2020

The Oil and Gas industry has historically relied on lagging indicators (e.g., number of spill events, volume of spill, number of well kicks, personal safety statistics) for measuring and monitoring safety performance. Even though these metrics provide some useful information on an organization's safety culture, they do not offer any predictive insights.

Leading indicators are metrics for measuring and monitoring events that can lead to or contribute towards an incident. Well control incidents are low frequency-high consequence events. Carefully developed and tracked leading indicators can provide valuable information for preventing significant control events.

Currently, a collaborative project is underway to engage the upstream oil and gas industry to develop leading indicators-based dashboard tools for predicting and thereby preventing well control incidents. The goal of this project is to develop a set of leading indicators-driven predictive tools with customizable dashboard displays, for multiple levels of decision makers, to constantly monitor and understand well operations risk from a process safety standpoint.

This tool would provide the users (from frontline to management) with role-specific information from status of engineering barriers (e.g., hydrostatic head, BOP status and health) to organizational process safety elements (e.g., procedure, compliance, design, risk management). The ‘processed’ information presented in a dashboard setting can be considered as early warning signs of well control events, which should drive targeted corrective actions to minimize risks in well operations. The project has already identified significant work in this area both from academic and industrial sectors, which will help to build the foundation for moving forward towards building a robust and useful Leading Indicators Dashboard.
Robust Chemical Flood Design for Maximum Recovery Using Updated Fluid Property Models
Authors: Khodaparast Pooya , Johns Russell T.
Published: October 2020

State-of-the-art chemical flooding simulators typically use nonpredictive phase behavior and property models to design a surfactant flood. For example, a variation of the black-oil model is often used to represent phase behavior in several commercial simulators. We examine the available methods including more recent physics-based models such as the HLD-NAC equation-of-state and their effects on overall recovery, front speeds, and breakthrough times. We implement the HLD-NAC EoS model in UTCHEM to examine the impact of changing salinity and other variables on the phase behavior and the recovery process. A novel predictive viscosity model is also implemented for the first time in UTCHEM to give a more accurate prediction of viscosity. We isolate the impact of salinity and other gradients on recovery in a one-dimensional homogeneous reservoir.

Results show that the composition path can enter the Winsor II+ region for certain changes in variable gradients. When the two-phase region is entered, the trailing injected fluid surpasses the chemical slug and contacts the oil bank directly. The microemulsion phase saturation is then decreased to immobile values so that surfactant is now immobile and oil recovery is significantly decreased. We further show that the presence of polymer - both in the buffer and the chemical slug - has little effect on the appearance of the arrested microemulsion and oil bank. Polymer does partially offset the negative effects by providing conformance control immediately after the microemulsion phase is trapped. The salinity gradient should be designed so that the composition path avoids the II+ lobe in its entirety, giving a robust and mobile slug with or without polymer. We propose a limit in injection salinity under which the II+ lobe can be avoided. We also show that the less accurate viscosity model overestimates recovery in a two-dimensional simulation of the chemical flood.
Considerations and New Approaches for Talent Development of Gen-Z in Oil and Gas
Authors: Capello Maria Angela , Al-Khashti Bashar
Published: October 2020

New generations face learning in different ways, but managerial styles prevail for decades, creating a gap that greatly affects talent development effectiveness. This creates, more than a gap, a risk, especially for ensuring the outcome of the training of individuals of Generation Z in the oil and gas industry, where safety in front of hazards needs to prevail, and where production optimization is a leading goal for the very sustainability of the industry.

This paper focuses on establishing the main differences in the learning style of the so-called Gen-Z or Genzers (Generation Z), and why fixing the tools, systems, approaches and even settings of their training is vital to ensure the development of skills and leadership trajectories, which will necessarily, ground their professional careers and their corporate success.

The urgency of implementing step-changes in the approach that Human Resources and Training departments take for developing Gen-Z is peremptory, most particularly for the change of style in mentoring, recognition and supervisory styles that will have to be used by their leaders.
Edge Computing: Continuous Surveillance and Management of Production Operations in a Cost Effective Manner
Authors: Sharma Abhishek , Samuel Prince , Gey Gian-Marcio , Kumar Sujit
Published: October 2020

E&P operators are aggressively looking to increase production with operational efficiency gains. Proactive well and field production management requires digital enablement of operations, with no data silos and data flowing seamlessly from the subsurface to the hands of the operator. With huge amounts of data being collected, it is imperative to apply data-driven techniques to gain more insights that can be utilized to better manage production. A data-driven approach can provide huge benefits for organisations holding vast amount of reservoir, production, and facilities data. It could provide insights into non-linear multidimensional relationships between parameters so that the field development is better understood and optimized. It could allow companies using a proactive approach towards field operations and equipment maintenance resulting in additional cost savings.

This paper presents various case studies where operators improved operational efficiency and optimize production utilizing edge-driven Industrial Internet of Things (IIoT) solutions. These edge IIoT solutions enable fast-loop control through a combination of physics and data-driven workflows, which empowers the operator to proactively manage their assets and focus attention on potentially problematic wells. The solution's architectural setup and ability to deliver fast-loop control workflows at the edge enables operators to successfully detect and manage potential issues such as artificial lift pumps, ultimately improving the performance. Additionally, this approach reduces the dependency upon domain experts to frequently analyze data. The high-frequency data capturing resulted in predicting equipment performance with confidence and allowing remote well management to reduce health, safety and environment (HSE) risks while decreasing logistics and maintenance costs.
Machine Learning Method to Determine Salt Structures from Gravity Data
Authors: Chen Jie , Schiek-Stewart Cara , Lu Ligang , Witte Susanne , Eres Guardia Karin , Menapace Francesco , Devarakota Pandu , Sidahmed Mohamed
Published: October 2020

In this paper, we developed an innovative machine learning (ML) method to determine salt structures directly from gravity data. Based on a U-net deep neural network, the method maps the gravity downward continuation volume directly to a salt body mask volume, which is easily interpretable for an exploration geophyisicist. We also studied the feasibility to apply the method to different gravity field data. We conclude that the ML based method from gravity data complements seismic data processing and interpretation for subsurface exploration. For the region where no or limited seismic data are available, this ML based salt identification can save iterative efforts (>50%) in the conventional gravity inversion process and identify major salt bodies in the region.
Water Isolation and Sand Control: Breaking Barriers with Expandable Steel Patch Technology
Authors: Guerrero Ximena , Medina Daniel Ricardo , Munoz Alberto , Rubiano Jhon , Bejarano Alied , Trujillo Hernando , Saltel Nicolas , Trillos Julian , Becerra Jerson , Castellanos Diego , Coronado Cesar
Published: October 2020

This paper describes the design, planning, and successful installation of a fit-for-purpose casing patch to isolate a water producing zone, the subsequent perforation of an adjacent zone, and a gravel pack completion in the same well for the first time worldwide. The proximity of the zones and the sand control requirements made the design and planning of this job a challenging task that is detailed in this manuscript.

The main producing zone in the SW-21 well watered out after few years of production. A second target was identified located just four feet below the main zone. To extend the life of the well and to add reserves from the secondary target, the upper 100% water zone had to be isolated. A fit-for-purpose, thin wall casing patch solution was designed to: allow perforation of the secondary target while maintaining patch integrity, allowing for the installation of sand control screens; and resist following gravel pack completion, by keeping the minimum recommended clearance between casing and screens, inside the minimal patch-reduced diameter.

The re-completions program consisted of: 1. Successful recovery of existing gravel pack from the main producing zone and thorough wellbore cleanup. 2. Casing patch installation consisting of a 23-ft long patch to isolate the water-producing zone. In this case, a specific engineering design analysis was required to ensure that, because of the very close distances between zones, the patch would still maintain integrity during perforation of the secondary target and the resulting patch overlap. 3. Successful integrity test to confirm upper interval isolation before perforating the lower interval. 4. A precise perforating operation carried out to perforate the secondary zone. Based on engineering recommendations, some length of the installed patch was perforated to guarantee a minimum unperforated distance of casing patch between zones to guarantee patch sealing features. 5. Once perforation was successfully accomplished, a gravel pack completion—inside the casing patch reduced diameter—was executed along the new zone for sand control purposes, and the well was put into production.

This paper presents the different interactions between a multidisciplinary research and development team, and completions and reservoir engineers to come up with a full solution for water isolation and sand control under such challenging conditions. For the first time in the world, a casing patch was used to isolate a water zone, and at the same time, perform a gravel pack completion inside the patch reduced diameter. Well performance, without any mechanical issues, confirms the success of the provided solution.
Optimal Downhole Flow Control Completion Designs in a Fractured Carbonate Reservoir Using Reservoir-Centric Simulation Approach
Authors: Amjad Bilal , Ogunsanwo Oloruntoba , Bawazir Mustafa , Batita Nabil , Siddiqui Mohammed
Published: October 2020

Long horizontal wells in naturally fractured carbonate reservoirs often exhibit very high water-cut within months of production because of the early arrival of water from natural fractures. Passive inflow control devices (P-ICDs) have been used globally to balance influx, delay water or gas breakthrough to prolong well life. However, some wells have continued to experience high water-cut despite the control measures. Image log review has revealed the uncertainty is in the identification of fractures and its conductivity networks. Two additional zonal control technologies are presented in this paper: on/off ICDs and intelligent (IC) or smart completions in comparison.

A software-based 3D reservoir model was built to represent a horizontal oil-producer in a fractured carbonate reservoir penetrating a thin oil rim. The first model simulated well production performance in a well with on/off ICD. Intervention was replicated in time (i.e., taking longer) to shut-off ICDs. The second model evaluated production forecast over the same period for the same well, this time equipped with an IC in the open hole (OH). Actions in this case were taken right away from the surface (i.e. without downhole intervention) to identify and restrict or shut-off intervals with water breakthrough.

Time-lapsed 3D reservoir model calibration is possible with ICs as they provide real-time downhole pressure and temperature across each interval. The timely control of zonal valves from surface actuation reduced production of water or gas. On/off ICDs, on the other hand, necessitated scheduling a production log (PL) to confirm the interval of water or gas breakthrough and performing coiled-tubing (CT) intervention to shut-off the problematic zone. Intervention comes at cost of interrupting well production and reducing net oil recovery. A simplified cost-benefit analysis of both cases showed that despite a higher initial capital investment in ICs, well operating costs were substantially lower with higher oil recovery. In IC solution, costs for running production logs and intervention tools were eliminated and so was the risk of losing these tools in the hole and the loss in production during the intervention period. Continuous monitoring of downhole pressure data helped reservoir characterization and prediction of reservoir production behavior without compromising production on-stream time.

A comparison of different reservoir flow control devices suggests that ICs are the optimal choice in some fractured carbonate reservoir conditions. They provide real-time monitoring of each producing zone and surface control of the flow control valve (FCV) settings in real-time as reservoir performance changes. They enable production testing evaluation—without production logging and interventive shifting with CT, i.e. to determine the source of water entry and optimization of multi-zone production without downhole intervention.
Coupled Versus Stratified Flow of Water and Hydrocarbon During Flowback and Post-flowback Processes
Authors: Moussa Tamer , Fu Yingkun , Dehghanpour Hassan , Hawkes Robert
Published: October 2020

Pore-scale images and core-scale imbibition experiments suggest that hydrocarbon and water tend to flow through their own pore network, referred to as "stratified flow". The objective of this paper is to investigate the occurrence of these phenomena at reservoir scale by analyzing flowback and post-flowback production data. Understanding multiphase flow regimes is the first step for selecting proper relative permeability curves and developing representative multiphase rate-transient models. Another objective of this paper is to investigate the harmonic decline (HD) behavior of water-oil ratio (WOR) versus cumulative water production volume and how it could be employed to compare load recovery performance of different wells. We analyzed flowback and post-flowback production data of six multi-fractured horizontal oil wells completed in Eagleford Formation. The proposed data-driven methodology involves using multiphase diagnostic plots of rate-normalized pressure, rate decline, and WOR. We applied this methodology to i) investigate the relationship between water and hydrocarbon at early production time; ii) model WOR with respect to cumulative water production; and iii) evaluate how fracturing/completion design parameters affect well performance.

The results show three key findings: i) During early production time, we observe independent flow regimes (stratified flow) of water and oil indicating their production under different drive mechanisms. Water is produced from an apparently closed tank comprising induced fractures and the surrounding stimulated matrix, and oil is produced independently at a significantly lower rate due to oil influx from matrix into fractures. ii) After jet-pump installation, we observe coupled flow of water and oil indicating their production under similar drive mechanisms provided by the pump. iii) Semi-log plot of WOR versus cumulative water production shows HD trend that is relatively less sensitive to operational changes compared to water rate-decline plots.
Improving ESPs Performance Using Sand Control and Downhole Chemical Treatment: Cases Studies in the Permian Basin
Authors: Zapp Ben , Vyas Shivani , Gonzalez Gustavo , Guanacas Luis , Portilla Carlos
Published: October 2020

This successful application of complementary systems helped to extend the runlife of the wells until the ESP needs to be resized to match the reservoir inflow capacity. The sand and chemical challenges need to be approached by gathering data starting from expected fluid production (Oil, Water, Gas), hydraulic fracturing design (frac sand size), and CWA (Complete Water Analysis). This paper proposes a new method to deal with sand and chemical problems in the ESPs. The solution includes three steps: Isolation method, sand control system, and down-hole chemical treatment. The isolation method primarily isolates the pump intake using cup packers, mechanical packers, or shroud. The sand control system considers static and dynamic principles whose length, open area, and separation efficiency depend on the particle size distribution, well completion, and fluid potential. Finally, the down-hole chemical treatment micro-encapsulates the original chemical components used on the surface and allows their installation and controlled dispersion down-hole below the sand control system. This paper includes the guidelines and simulations required to design the complete solution.
A Stability Criterion for Gas-Liquid Flow in a Well-Flowline-Separator System
Authors: Moran Ochoa Oscar , Vázquez Nolasco Sergio , Díaz-Soto Pérez Ignacio , Fairuzov Victor , Fairuzov Yuri
Published: October 2020

Oil and gas gathering systems can experience flow instabilities characterized by cyclic pressure variations and liquid or free water surges out of the flowlines that typically cause liquid or gas handling problems in receiving facilities and dynamic external loads in elbows and T-junctions. This study describes a new mechanism of instability of gas-liquid flow in a well-flowline-receiving facility system referred to in other industrial applications as the density or liquid holdup wave oscillations (DWO). Unlike instability phenomena related to hydrodynamic slugs, terrain-induced slugs or riser-induced severe slugging, this type of instability is a result of multiple feedback effects between the flow rate, pressure drop, and liquid inventory (the total volume) in the flowline. The specific DWO instability mechanism proposed in the present study is related to generation and propagation of a liquid holdup wave with a large amplitude and wavelength several times greater than the length of a hydrodynamic or terrain-induced liquid slug. A new stability criterion to predict the DWO onset is proposed based on Ultra-High Definition (UHD) simulations of three-phase gas-oil-water flow to accurately predict the liquid inventory. Field data showing a transition from unstable to stable operation in an offshore oil production system are presented. The system is used to transport produced fluids from a satellite platform with naturally flowing and gas-lifted wells to a central platform with processing facilities, via a 30-in. diameter flowline. The stability criterion was used to identify the root cause of large-amplitude oscillations of pressure and flow rate in the flowline. Thus, proposed dynamic two-phase flow instability mechanism and criterion are a cost-effective and practical method for predicting instability onset conditions and developing mitigation strategies in existing and new-built production facilities.
Advances in Understanding Relative Permeability Shifts by Imbibition of Surfactant Solutions into Tight Plugs
Authors: Yousefi Mohammad , Yuan Lin , Dehghanpour Hassan
Published: October 2020

Various chemical additives have been recently proposed to enhance imbibition oil recovery from tight formations during the shut-in periods after hydraulic fracturing operations. Although, soaking experiments under laboratory conditions usually confirm the performance of such additives, their effects on oil regained permeability during the flowback process are poorly understood. This is mainly because measuring effective permeability of such low-permeability rocks is extremely challenging. We develop and apply a laboratory protocol mimicking leak-off, shut-in, and flowback processes to evaluate the effects of fracturing fluid additives on oil regained permeability. We modify the conventional coreflooding apparatus to measure oil effective permeability (koeff) before and after the surfactant-imbibition experiments. Adjusting the system total compressibility allows quickly achieving steady-state conditions at multiple ultra-low flowrates. We apply the proposed technique on two tight plugs with and without initial water saturation (Swi), and observe pressure humps during the flowback process that can be explained mathematically using the fractional-flow theory.

Spontaneous imbibition of the surfactant solution into the two oil-saturated plugs results in recovery of around 20% of the initial oil. For the plug with Swi = 0, koeff is reduced from around 3 µD to 1 µD, indicating the adverse effect of water trapping over the favorable effects of interfacial tension reduction and wettability alteration by the surfactant. For the plug with Swi = 0.21, koeff increases from 0.85 µD to 1.08 µD that can be explained by the combined effects of Swi reduction and wettability alteration, favorably shifting the oil relative permeability curve.
Spatially Resolved NMR T2 Distributions for Pore Size, Surface Relaxivity and Gas Relative Permeability Mapping of Gas Carbonate Reservoirs
Authors: Machicote Saida , Visconti Luca , Santonico Dario , Miarelli Marco , Barbacini Giulia , Pirrone Marco , Bona Nicola
Published: October 2020

A comprehensive petrophysical evaluation of carbonates requires a well-designed workflow to enable rapid integration of data from cores and logs. We describe a methodology that makes use of spatial NMR T2 distribution measurements performed along the length of a core plug in conjunction with micro-tomographic imaging techniques to obtain: 1) the relationship between pore body and pore throat size, 2) surface relaxivity as a function of pore size and 3) a gas relative permeability predictor for the NMR log. An initially fully water saturated core plug is centrifuged in air. Because of the centrifugation, a saturation profile forms in the plug. The plug is virtually treated as a series of thin slices. Water saturation is assumed to be uniformly distributed in each slice but it will vary from one slice to another. Spatially resolved NMR measurements provide the T2 distribution of each slice. For each slice, water saturation and the capillary pressure applied to it during centrifugation are also known. Let Pc1 and Pc2 be the capillary pressures applied to two adjacent slices and let γ be the water-air interfacial tension. Subtracting the T2 distributions of the two slices gives the pore body size distribution of a narrow region of pores whose pore throats range from 2γ/Pc1 to 2γ/Pc2. Doing this calculation for all couples of adjacent slices provides a relationship between pore body and pore throat sizes that is defined over a wide range of sizes.Surface relaxivity is estimated by matching the NMR-derived pore body size distribution to high resolution images (X-ray Micro-CT and SEM) of the core plug.For the gas relative permeability predictor, a SDR-like permeability is assigned to each slice. The parameters in the SDR equation are then optimized by matching the measured effective air permeability to the harmonic mean of the permeabilities of the individual slices.

Since one single centrifugation step is needed, the above data (1, 2 and 3) are obtainable in few days. The methodology was applied to a large gas carbonate reservoir. The body/throat size relationship proved to be useful in rock-typing work and a gas relative permeability profile was defined in one of the wells. This represented a significant contribution to our understanding of the reservoir and to the achievement of the objective of reducing the time-to-market.

On average, six data-points for the body/throat size relationship are generated for each analyzed core plug. Standard core analysis methods do not provide such a relationship. Usually, surface relaxivity is an assumed parameter but this methodology allows us to estimate it. Relative permeability cannot be estimated directly from logs and this methodology represents a step towards this important goal.
Evidence of Significant Casing Erosion Damage Caused by Leaking Frac Plugs During Stimulation's Leads to Uncertain Proppant Distribution Results
Authors: Strubberg Carl , Arcanjo Diego , McDonald Joe , Lilly Todd , Roberts Glyn
Published: October 2020

Technology to interrogate perforations to quantify cluster efficiency in limited entry, plug and perf completions has improved in operational efficiency, image quality and quantity. The entire pipe wall of the lateral is now visually imaged, and the discovery of significant casing erosion damage caused by leaking frac plugs during stimulations is easily observable, often multiple times in the same well. The effect of a breached casing with significant erosion between stages could potentially divert proppant from the intended perforation targets leading to reduced cluster efficiency and uncertainty of proppant distribution results.

Video images have been used for several years to evaluate proppant distribution. The recent introduction of array side-view camera technology now provides highly detailed images of the full 360 circumference of the wellbore over extended intervals. Image logging methods for unconventional wells have changed from capturing a limited number of images of individual perforations through a small ‘spy hole’ to a complete panoramic view of the entire wellbore. Perforations, connections and everything in between can be efficiently imaged and analysed. Enhanced processing methods have additionally improved visualization of results and allowed quantification of areas of interest with image-based dimensioning.

Greatly enhanced borehole image coverage has allowed the discovery of unintended interactions that can be very detrimental to fracture treatments. Evidence of these unwanted effects that were previously difficult to diagnose are now uncovered during routine fracture diagnostics. Evidence includes

Erosion at plug setting depths has been observed in a relatively high proportion of wells Multiple casing breaches have also been observed in some wells with as many as 35% of plug setting depths subject to this issue The areal extent of erosion at plugs has been measured in the range of 10% of the casing circumference up to 100% full parting While the exact effects on the fracture treatment of potentially large volumes of fluid and proppant being diverted away from their intended target has not yet been quantified the catastrophic effect on well integrity is very clear.

Examples, analysis methods, results, primary conclusions, and other relevant findings are discussed in detail.

The technology we discuss is undoubtedly helping raise awareness in the industry of the potential extent of this previously under-diagnosed issue. Increased awareness and improved understanding of the issue will lead operators to better equipment selection, enhanced procedures and ultimately more productive and profitable wells. Hydraulic fracture performance will improve while cases of compromised well integrity will decline.
An Artificial Intelligence Technology for Predictive Operation and Maintenance of Crude Oil Gathering Systems
Authors: Fairuzov Victor , Fairuzov Yuri
Published: October 2020

Localized internal corrosion, paraffin/wax deposition, microbiologically induced corrosion or MIC, and solids accumulation are some of the primary issues throughout a pipeline's lifecycle, especially, at low flow conditions. Although significant progress has been made in the development of methodologies and standards for detecting internal corrosion in different types of pipelines, little work has been done on providing cost-effective methods and technologies for the implementation of preventive corrosion strategies. Pigging and chemical inhibition continue to be the first choice of oil and gas producers in addressing asset integrity and flow assurance issues. This paper describes an Artificial Intelligence (AI) technology that enables operators of oil and gas gathering facilities to transport produced fluids as a sequence of alternating controllable fluid batches to remove stationary beds of solids or soft wax from flowlines and pipelines, including unpiggable lines, without human input. The AI technology is used to determine fluid batch launch times to maximize the system performance. A brute-force search algorithm was developed for this purpose to maximize the number of batches launched during one operation cycle. An example is presented to demonstrate the system operation in an offshore oil gathering system. Pigging and chemical inhibition costs can be substantially reduced, and the useful life of pipeline infrastructure and facilities can be extended using the proposed technology solution at all stages of field development.
Mechanical Behavior of Thermosensitive Screen Applied for Wellbore Collapse
Authors: Qin Xing , Duan Youzhi , Yue Hui , Ai Shuang , Hou Qian , Jing Bo
Published: October 2020

In response to the borehole instability problems such as wellbore collapse and sand production, which often occur in drilling and completion, a thermosensitive screen technology that can expand spontaneously at a specific temperature has been developed. The radial expansion of the screen allows for annulus filling and borehole strengthening. This paper provides a theoretical evaluation of the comprehensive performance of the thermosensitive screen on wellbore collapse. The results show that the thermosensitive screen barely expands before reaching the conversion temperature, which facilitates the screen's descent into the target depth. After reaching the destination depth, it can be stimulated to expand under the influence of conditions such as formation temperature. The extruding stress after screen expansion contacting the wellbore wall can effectively improve the stress distribution around the near-wellbore and reduce the shear instability caused by the difference between the maximum and minimum principal stress of the formation, while at the completion stage of production, it can effectively improve the flowing downhole pressure, thus increasing the drawdown pressure.
Analysis of Reasons for Differences in Proved Reserves Estimates with PRMS and SEC Regulations
Authors: Morales Enrique , Lee W. John
Published: October 2020

Two recent papers (URTeC 3003052 and SPE 200626) have presented detailed investigations of reasons why proved reserves estimates based on PRMS principles and on SEC regulations differ by substantial amounts in several instances. This paper synthesizes and extends this previous work and addresses implications of differences and reasons for differences.

We examined the relatively limited number of cases in which reserves filers have reported reserves as of a given date based on both PRMS definitions and SEC regulations. To understand the differences, we also reviewed numerous annual reports and comment letter exchanges between reserves filers and the SEC staff during the period 2009 to 2019. We devoted attention to identify differences that might arise from different interpretations of reserves definitions adopted by the two different systems. Since COGEH is quite like PRMS regarding the use of forecast prices and costs, we extended our analysis to include comparisons with COGEH proved reserves when addressing prices and costs as root causes for the differences.

While we examined many potential reasons why proved reserves using SEC and PRMS definitions and principles are different, we found three that appeared to be dominant. The first is that the SEC requires use of current prices in reserves estimates whereas PRMS (and COGEH) allow use of forecasted prices (often escalated) for sales volumes. The second is that PRMS requires firm evidence that a recovery project for resources has been fully approved and funded to reach classification as reserves with the status of "Approved for Development," but also allows recovery projects which are reasonably expected to receive approval to be classified as reserves with the status of "Justified for Development." Examination of comment letter exchanges indicates that the SEC also requires "reasonable certainty" that a "Final Investment Decision" will be reached to classify resources as reserves, essentially the same as the PRMS requirement for "Justified for Development" status. Comment letter exchanges indicate that this is the SEC staff's customary practice even though a literal reading of SEC guidance might suggest a stricter standard. The implication is that some reserves filers may unknowingly limit their reserves bookings, which might not be in the filers' or other stakeholders' best interests. The third reason is the five-year SEC development limitation (unless specific circumstances justify a longer time).

Interpretation of reserves disclosure requirements in principles-based regulations based on how they are enforced in practice may serve investors and owners of resources better than assumptions based on literal readings of these regulations.
Optimization of Liquid-Assisted Gas Lift Processes for Production Enhancement by Using Transient Computer Simulations
Authors: Thiberville Caitlyn , Wang Yanfang , Kam Seung Ihl
Published: October 2020

Reservoir pressure depletion and liquid loading depress production in mid-to late-life producing wells. While pressure depletion can be difficult to combat and requires large scale solutions, liquid-loaded production tubing is easily remedied by on-site, individualized artificial lift solutions, such as sucker rod pumping, plunger lift, or gas lift, to name a few. A recent experimental study of Coutinho et al. (2017), using 2,788 ft depth vertical well with 2.88-inch ID tubing and 4.89-inch ID casing, shows that liquid-assisted gas lift (LAGL) processes can overcome difficulties in conventional gas lift, one of the most popular artificial lift methods in both onshore and offshore environments, and aid in cost reduction for operations by decreasing the onsite energy and infrastructure needs to unload a well.

Following the outcome of the experimental study, this study investigates how to further refine LAGL operations by conducting transient computer simulations using OLGA. The first step is to match the experimental data (i.e., history of bottomhole pressure and injection pressure) to extract model parameters for the simulations to follow, the second step is to perform 119 different simulation runs as well as analysis of resulting pressure and liquid-holdup histories in a wide range of gas and liquid flowrates, and the last step is to show how to implement the optimization technique by using the contour maps of variables and parameters of interest to optimize.

The results show that the two contour maps of required maximum injection pressure and liquid holdup in the tubing, as a function of gas and liquid flowrates, can serve as a useful means of seeking the optimum operating conditions. In addition, it is also shown that there are multiple sets of two contour maps, equivalently, to be employed for a similar analysis depending on various field scenarios or constraints (such as compressor capacity, limited gas supply, and separator capacity). Pressure loss and phase fraction, through complicated multiphase flow physics and flow regimes, play a key role behind the presence of optimum operating conditions during liquid unloading process.
Effect of Silica Nanoparticles on the Oil Recovery During Alternating Injection with Low Salinity Water and Surfactant into Carbonate Reservoirs
Authors: Olayiwola Saheed Olawale , Dejam Morteza
Published: October 2020

Application of nanoparticles (NPs) for enhanced oil recovery (EOR) has gained a lot of attention in recent years. Several laboratory studies have shown that the injection of nanofluid leads to a significant amount of oil recovery by modifying the fluid and rock/fluid properties, including the viscosity, interfacial tension (IFT), and wettability. Although the potential of NPs to improve oil recovery is magnificent, the effect of NPs during alternating injection is still vague. The main objective of this study is to investigate the best recovery mechanisms during alternating injection of NPs, low salinity water (LSW), and surfactant and transform the results into field-scale technology.

The results of the laboratory coreflooding experiments, which are performed on different core plugs taken from Indiana limestone (carbonate) reservoir, are presented in this study. To determine the best recovery mechanisms, different combinations of alternating injection of silica NPs, LSW, and Sodium Dodecyl Sulfate (SDS) surfactant into the selected cores are conducted at temperature and pressure of 70 °C and 3,000 psi, respectively. The experimental procedure is designed to reflect the best industrial practice for the injection of fluids into the reservoir. This study also investigates the effect of silica NPs on the IFT and the wettability at aforementioned conditions.

The outcome of these experiments revealed that the tertiary injection of NPs results in additional oil recovery beyond the limit of LSW. An additional oil recovery of 5-6% is achieved by alternating injection of NPs and surfactant after injection of LSW. Therefore, a total oil recovery of 8-11% is obtained from alternating injection of LSW, NPs, and surfactant. However, it was observed that less than 5% of the oil in place is recovered from the tertiary alternating injection of NPs dispersed in LSW and surfactant. The difference in the results is attributed to the wettability alteration by the NPs beyond the limit of the LSW and the reduction in the IFT with/without surfactant. The interpretation of the results of this study improves the understanding of the key mechanisms and the best recovery mechanisms for the application of NPs for EOR in carbonate reservoirs.
Multi-Phase Rate Transient Analysis Considering Complex Fracture Networks
Authors: He Youwei , Tang Yong , Qin Jiazheng , Yu Wei , Wang Yong , Sepehrnoori Kamy
Published: October 2020

Application of horizontal wells and hydraulic fracturing achieves commercial productivity of unconventional oil and gas resources. Complex fracture networks (CFN) provide flow channels and significantly affect well performance in unconventional reservoirs. However, traditional rate transient analysis (RTA) models barely consider the effect of CFN on production performance. Besides, the impact of multi-phase flow on rate transient behaviors is still unclear. Neglecting these crucial effects could cause incorrect rate transient response and erroneous estimation of well and fracture parameters.

To fill this gap, this paper investigates the multi-phase rate transient behaviors considering CFN, and tries to investigate in what situations the multi-phase model should be used to obtain more accurate results. Firstly, an embedded discrete fracture model (EDFM) is generated instead of local grid refinement (LGR) method to overcome the time-intensive computation performance. The model is then coupled with reservoir models using non-neighboring connections (NNCs). Secondly, eight cases are designed using the EDFM technology to analyze the effect of natural fractures, formation permeability, and relative permeability on rate transient behaviors. Thirdly, Blasingame plot, log-log plot, and linear flow plot are used to analyze the differences of rate transient response between single-phase and multi-phase flow in reservoirs with CFN. For multi-phase flow, severe deviations can be observed on RTA diagnostic plots compared with single-phase model. The combination of three kinds of RTA type curves can obviously characterize the differences from early to late flow regimes and improve the interpretation accuracy as well as reduce the non-unicity. Finally, field application in Permian Basin demonstrates that multi-phase RTA model and type curves are required for analyzing the production and pressure data since single-phase RTA analysis will lead to big errors for interpretation results.