bluuebunny/crossref_metadata_2025_split huggingface dataset:
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.