bluuebunny/crossref_metadata_2025 huggingface dataset:
Sub-Surface Driven Connectivity Descriptions in the Montney and the Duvernay Inform the Applicability of Single-Point Versus Multi-Point Well Architectures
Authors: Stephenson Ben , Bai Taixu , Fay Mathew , Galan Earl , MacDonald Jeff , Carduner Ryan
Published: September 2019

A single-point entry completion architecture has been implemented in several hydraulically stimulated resource plays across North America. The objective is to understand whether the innate properties of the rock and what we can diagnose about how it hydraulically fractures can inform the question of applicability of single-versus multi-point completion designs.

Wells were treated using a single-point entry design in the Montney and the Duvernay and an assessment of well performance was carried out. Multiple diagnostic pads have been carried out over several years in both formations, including microseismic and geochemical fingerprint data allowing for a general characterization of the gross geometry and connectivity. Initial results from a fiber are available in the Montney with a single point completion design. The fracture diagnostic data was compiled and described in the context of the nine main sub-surface controls on the connectivity.

In the Montney, it is relatively clear how completion intensity changes, like stage length, in single-point entry wells change the production performance outcome. In the Duvernay, there is significantly more uncertainty. This contrast contributed to the decision to treat several follow-up pads in the Montney via a single-point entry design, whereas a multi-point plug and perf completion is preferred for the Duvernay wells. Costs and stage isolation are considerations, but one other contributing explanation is that the dominantly planar fracture geometry in the Montney enables each stage to contribute proportionally, thus ensuring the stimulation distribution effectiveness from the near-to the far-field.

The dry-gas area of the Montney is very stiff, with an absence of natural fractures, a paucity of faults, no containment issues and no significant frac barriers. Conversely, in the Duvernay, the inherent complexity in the fracture geometry complicates the stimulation distribution effectiveness in the far-field. Furthermore, the lower mobility of a liquids-rich hydrocarbon system probably benefits from the potentially tighter frac spacing, possible in a multi-cluster design, even with a probable increase in non-uniformity over single-point.

It is hypothesized that in formations that develop complex fracture geometries, ‘putting all your eggs in one basket’ with a single-point entry design, needs to be assessed along with the other value drivers for the well architecture selection.
A Game Changer Data Acquisition Technology : Field Wide Gaslift Optimization through the Application of Welltracer Technology in a Mature Offshore Field
Authors: Mohd Khalil Muhammad Idraki , Chang Claire Li , Amran Amierul , Kok Jason Chin
Published: September 2019

90% of Field T production relies on Gas lift as means of artificial lift. Typical surveillance strategy in assessing the health of the gas lifted wells is to deploy flowing gradient survey (FGS) in tandem with surface welltest. However, in the case of Field T, this technology meets its limitation in investigating prolific wells due to its current well mechanical condition and dual string completion environment. Welltracer technology application in the field has broken the barrier in evaluation of these wells in Field T.

The Welltracer application is a non-invasive data acquisition method which measures the travel time and concentration of the CO2 return which is introduced upstream of the gas lift header. The interpreted results allow for the identification of injection points and rate. This simple idea opens up opportunity for gas lift performance evaluation of wells in Field T that was not possible through the conventional approach of FGS. This breakthrough is vital for Field T as some of the wells are facing either one or more of the following problems i.e. dual string wells with gas robbing issues, tubing leak, restricted tubing due to pack-off and multi-point injection.

Twenty-three surveys and analysis were completed during the first application in Field T. The opportunity identified from the survey were categorized depending on the resources and timeframe required to execute the changes. Four enhancement opportunities were identified which only required surface valve manipulation were executed immediately and showed instant results. Other than additional barrels, the results of the campaign have a tremendous value of information that changed the earlier comprehension of the existing problems in some of the wells.

This paper discusses the results of the application of the technology in Field T. This paper will also elaborate on the lessons learned and improvement recommendations in terms of project identification, execution and planning. Another important highlight that will be discussed is the limitation and assumptions made to further enhance the understanding of the Welltracer technology.
Performance Analysis of the Artificial Lift Systems for Heavy Oil Wells in the Egyptian Eastern Desert
Authors: El Gharbawi Mahmoud Atef , Elgibaly Ahmed Ahemd , Salem Adel Mohamed , Abbas Mohamed
Published: September 2019

This paper describes the implementation of a performance analysis (PA) review and a comprehensive root cause failure analysis (RCFA) for the artificial lift system (ALS) failures in heavy oil wells. The subject wells, located in Egyptian Eastern Desert (EED), have been operated by Canadian-Egyptian joint venture. Progressive cavity pump (PCP) and beam pump (BP) have been selected as the preferred ALS methods. With the objective of improving ALS performance, RCFA identifies the main causes of ALS failures and proposes guidelines and recommendations with a new open source service for the current and future development for EED Oil companies.

PA has been applied using some Key Performance Indicators (KPI), such as: failure index, recurrence index, and average run life in order to track all failed and crucial issues. RCFA has been applied to different ALS, such as: BP and PCP. Therefore, the definition or limitation of the boundaries of each system and the classification of failures were performed. RCFA covered failures between 2012 and 2018 for average 150 active wells and 622 failures. Finally, the new open source service applied as a trial to evolve the failure tracking and decision making methodology.

PA review showed a high failure and recurrence index that reached 3.0 and 3.7, respectively, in 2014 then declined to 1.0 and 1.7, respectively, in 2017 as a result of comprehensive corrective actions implemented. RCFA showed that rod string failure in BP was and still is a dominant failure with 200 failures over the last six years. Moreover, Down-hole pump failure in PCP was the major PCP failure system although its failures declined from 80 failures in 2014 to 14 failures in 2018. Several field cases were presented to cover the dominant cause of failures for both BP and PCP wells. Most wells had a significant improvement in their mean time to failure (MTTF) after reviewing design, installation and operation procedures.

The procedure for carrying out this methodology and implementing lessons learned has been presented in this paper. In addition, the new open source integration service provides an increased visibility about individual well performance issues and more broadly, about field performance and ALS failures.
Evaluating Precision of Fluid/Casing Design for Annular Pressure Build-Up APB Application Using Machine-Learning Tools
Authors: Kulkarni Sandeep D. , Vyas Aditya , Gupta Himanshu
Published: September 2019

Annular Pressure Build-up (APB) is caused by heating of the trapped drilling fluids (during production) which may lead to burst/collapse of the casing or axial ballooning, especially in subsea HP/HT wells. The objective of present paper is to apply machine-learning tools to increase precision of the APB estimation, and thereby improve the fluid and casing design for APB mitigation in a given well.

The APB estimation methods in literature involve theoretical and computational tools that accommodate two separate effects: volumetric expansion (PVT response) of the annulus drilling fluids and circumferential expansion (and corresponding mechanical equilibrium) of the well casings. In the present work, machine-learning algorithms were used to accurately model ‘fluid density=f(T,P)’ based on the experimental PVT data of a given fluid at a range of (T, P) conditions. Sensitivity analysis was carried out to demonstrate improvement in precision of APB estimation (for different subsea well scenarios employing different fluids) using the machine-learning based models.

The study demonstrated that, in several subsea scenarios, a relatively small error in the experimental fluid PVT data itself can lead to significant variation of in APB estimation. The machine-learning based models for ‘density = f(T,P)’ for the fluids ensure that the cumulative error during the modeling process is minimized. The use of certain machine-learning based density models was shown to improve the precision of APB estimation by several hundreds of psi. This advantage of the machine-learning based density models was employed to improve the casing/fluid design for APB mitigation; the case was demonstrated for a subsea well scenario. Accordingly, the work may be used to mitigate the APB issue in the subsea HP/HT wells.
Field Case Studies of Downhole Electric Heating in Two Horizontal Alberta Heavy Oil Wells
Authors: Penny Scott , Karanikas John M , Barnett Jonathan , Harley Guy , Hartwell Chase , Waddell Trent
Published: September 2019

Downhole electric heating has historically been unreliable or limited to short, often vertical, well sections. Technology improvements over the past several years now allow for reliable, long length, relatively high powered, downhole electric heating suitable for extended-reach horizontal wells. The application of this downhole electric heating technology in two different horizontal cold-producing heavy oil wells in Alberta is presented.

The first field case study discusses the application of electric heating in a mature, depleted field as a secondary recovery method while the second case study examines a virgin heavy oil reservoir, where cold production by artificial lift was economically challenged. The completion, installation, expected and actual results of both cases studies are compared and contrasted.

Both field deployments demonstrate the benefits and efficacy of applying downhole electric heating. In the case of the mature depleted field, electric heating resulted in a 4X-5X increase in oil rate, sustained over a period of close to two years. The energy ratio of the heating value of the incremental produced oil to the injected heat was slightly over 7.0. In the virgin heavy oil field, electric heating reduced the viscosity of the oil in the wellbore from time zero, which allows for higher rates of oil production along the complete length of the long horizontal lateral at higher, if desired, bottomhole pressures than in a cold-producing well. This degree of freedom may ultimately allow for an operating policy that suppresses excessive production of dissolved gas, thereby helping conserve reservoir energy. Early production data in this field show 4X-6X higher oil rates form the heated well than from the cold-producing benchmark well in the same reservoir.

Numerical simulation models, which include reactions that account for the foamy nature of the produced oil and the downhole injection of heat, have been developed and calibrated against field data. The models can be used to prescribe the range of optimal reservoir and fluid properties to select the most promising targets (fields, wells) for downhole electric heating as a production optimization method, which is crucially important in the current low oil price scenario. The same models can also be used during the execution of the project to explore optimal operating conditions and operating procedures.

Downhole electric heating in long horizontal wells is now a commercially available technology that can be reliably applied as a production optimization recovery scheme in heavy oil reservoirs. Understanding the optimum reservoir conditions where the application of downhole electric heating maximizes economic benefits will assist in identifying areas of opportunity to meaningfully increase reserves and production in heavy oil reservoirs in Alberta as well as around the world.
An Efficient, Robust, and Data-Oriented Inversion Method for Noisy T2 Echo Trains
Authors: Li Baoyan , Arro Roberto , Thern Holger , Kesserwan Hasan , Jin Guodong
Published: September 2019

For NMR logging of hydrocarbon bearing formations, the inversion of T2 echo trains is a critical pre-processing step to compute porosity, permeability, and fluid saturations of formations. To accurately and efficiently invert NMR measurement data, a new inversion method is presented to compute the optimal solution of T2 distribution with a unique optimal regularization factor for NMR logging data processing. This inversion method has no assumption about the white noise of a T2 echo train.

A new supplementary nonlinear equality constraint was introduced to optimize the solution of T2 distribution by explicitly taking into account the measured noise of a measured T2 echo train. An efficient iterative algorithm has been developed to solve the nonlinear optimization problem defined in the new inversion method. An initial-guess solution of the regularization factor was proposed for accelerating the searching process of the regularization factor.

The new inversion method has been verified with synthetic T2 echo train data and applied to process T2 echo train data of core samples of carbonate and Berea sandstone formations that are saturated with different fluids. This method has also been compared with conventional methods. The testing and comparison results show that: The optimal solution of T2 distribution from the new inversion method has a unique solution that is independent of the pre-selected values of regularization factor, so does the regularization factor. The optimal solutions T2 distribution and regularization factor will be convergent to their true solutions when the SNR of echo train data becomes sufficiently high.The computation cost for searching the optimal solutions of T2 distribution and regularization factor using the new nonlinear optimization algorithm is only a few iterations.The initial-guess solution of the regularization factor is more close to the solution determined from the S-curve method, which could be higher than the optimal solution of the regularization factor searched in the new inversion method.
Chemical Flood of a Viscous Oil with Novel Surfactants
Authors: Panthi Krishna , Weerasooriya Upali , Mohanty Kishore
Published: September 2019

The goal of this work is to evaluate the applicability of a novel set of surfactants to enhance recovery from a viscous oil, high temperature, high permeability, clastic reservoir. A large number of novel short-hydrophobe based surfactants/cosolvents were designed and synthesized. As these surfactants do not require expensive aliphatic alcohols for their synthesis, they are likely to be less costly than conventional anionic surfactants. Here only phenol hydrophobe based non-ionic surfactants with varying number of propylene oxide (PO) and ethylene oxide (EO) groups are discussed. These surfactant molecules were investigated for their aqueous stability limits, interfacial tensions (IFT) with a viscous crude oil and oil recovery from sandpack or sandstone cores. Surfactant phase behavior experiments with viscous crude oil showed low IFT (not ultralow) for single surfactant systems. Only one surfactant (Phenol-7PO-15EO) formulation was chosen for coreflood in sandpack and sandstone cores. Water flood recovered about 50% original oil in place (OOIP) and reduced the oil saturation to about 48% in the high permeability sandpacks. The tertiary surfactant polymer flood with Phenol-7PO-15EO increased the cumulative recovery to 99% for sandpacks. The oil recovery was insensitive to injection brine salinity in the range studied. As the permeability decreased, the tertiary oil recovery decreased if the permeability is lower than 7 Darcy. Surfactant-polymer (SP) formulations with this surfactant can be recommended for high permeability sandstone reservoirs with viscous oils, but not for sub-Darcy sandstones.
CT Coreflood Study of Transient Foam Flow with Oil
Authors: Tang Jinyu , Vincent-Bonnieu Sebastien , Rossen William R.
Published: September 2019

We present a CT coreflood study of foam flow with two representative oils: hexadecane C16 (benign to foam) and a mixture of 80 wt% C16 and 20 wt% oleic acid (OA) (very harmful to foam). The purpose is to understand the transient dynamics of foam, both generated in-situ and pre-generated, as a function of oil saturation and type. Foam dynamics with oil (generation and propagation) are quantified through sectional pressure-drop measurements. Dual-energy CT imaging monitors phase saturation distributions during the corefloods. With C16, injection with and without pre-generation of foam exhibits similar transient behavior: strong foam moves quickly from upstream to downstream and creates an oil bank. In contrast, with 20 wt% OA, pre-generation of foam gives very different results from co-injection, suggesting that harmful oils affect foam generation and propagation differently. Without pre-generation, initial strong-foam generation is very difficult even at residual oil saturation about 0.1; the generation finally starts from the outlet (a likely result of the capillary-end effect). This strong-foam state propagates backwards against flow and very slowly. The cause of backward propagation is unclear yet. However, pre-generated foam shows two stages of propagation, both from the inlet to outlet. First, weak foam displaces most of the oil, followed by a propagation of stronger foam at lower oil saturation. Implicit-texture foam models for enhanced oil recovery cannot distinguish the different results between the two types of foam injection with very harmful oils. This is because these models do not distinguish between pre-generation and co-injection of gas and surfactant solution.
Frac Plug Pump Down Efficiencies and Techniques
Authors: Walton Zachary , Nichols Matthew , Fripp Michael
Published: September 2019

Plugs for hydraulic fracturing generally are pumped into horizontal wellbores. Initially, the goal was to get the plugs to depth without careful consideration of the amount of water used in the pumping. As the industry has grown, a better understanding of pump-down methods and techniques has resulted in a realization that these pumping inefficiencies should be improved.

When completing a horizontal well using the plug-and-perf technique, water is required to push the bottom hole assembly (BHA), containing a frac plug, to the target depth. With over one million frac plugs having been pumped in North America, large data sets are available to quantify the pump-down efficiency of these operations. This past information, along with a working model of how pump down works, can be used to promote improvements in pump-down efficiency, reducing water usage and rig time.

The efficiency of the pump-down operation can be calculated based on pump time, displacement volume, and the actual volume of fluid pumped. This type of information can be recorded during operations. The pump-down efficiencies can be calculated as a percentage of actual versus calculated volumes pumped and is often expressed as a relational number, such as how much fluid is needed per 100 feet of casing. These numbers can be used as a metric for the amount of water and time required to move the plug to its desired location.

Over 10,000 frac plug pump downs from diverse North American regions were analyzed to attain a baseline for efficiency during frac plug pump down operations. The force, pressure, and fluid velocity effects acting on the BHA during pump down were analyzed to understand how to better quantify methods and designs that increase or decrease efficiency. Finally, procedures were mapped out on the operational units used in pump down to understand the potential impacts on efficiency.

The result is a guide on gauging pump-down efficiency of past operations while understanding methods to increase these efficiencies in the future. This framework can be used to view how a frac plug is pumped downhole while understanding the relationships that control its efficiency. This model can be used to evaluate past operations as well as design for future operations to increase overall efficiencies and decrease water usage and time on location.
Technical Review of Tubing Deployed Flow Control Devices at MacKay River
Authors: Gohari Kousha , Becerra Moreno Oscar , Romanova Uliana , O'Hagan Dermot , Mende Anjaneyalu Abilash , Gaviria Fernando
Published: September 2019

Steam Assisted Gravity Drainage (SAGD) is a complex process and often requires more control relative to conventional applications during production operations. Flow Control Devices (FCDs) have been identified as a technology that offers improved efficiency of the process while simplifying the operations. The first FCD completions were installed in SAGD wells in Canada over a decade ago with the intention of improving the steam chamber conformance and reducing the steam-oil ratio (SOR). While it is widely understood that FCD completions, for the most part, have helped achieve the desired uplift for SAGD producers, further optimization could be made on future completion designs and operation strategy by looking at actual performance data from previous installations. The objective of the study was to obtain key design parameters and considerations for future FCD completion designs.

The majority of FCD completions in MacKay River were tubing deployed, installed in previously producing wellbores (retrofit). This study looks at 11 wells that were completed with a Baker Hughes FCDs. The analysis was broken down into 2 segments: production analysis and modelling. Production strategy implemented for each well was taken into account to eliminate variances. The modelling used a combination of steady state simulation (presented in this paper) and numerical simulation (to be presented in part II).

The study showed that TD FCDs improve the performance of SAGD well pairs when implemented in the appropriate candidate wells. An important outcome was the development of a candidate wells’ selection criteria, to ensure the retrofit completion improved performance and did not exacerbate other problems. Furthermore, design consideration were identified to improve the performances of future TD FCD installations.
Productivity Decline: Improved Production Forecasting Through Accurate Representation of Well Damage
Authors: Li Yan , Zaki Karim , Tan Yunhui , Wu Ruiting , Rijken Peggy
Published: September 2019

PI (Productivity Index) degradation is a common issue in many oil fields. To obtain a highly reliable production forecast, it is critical to include well and completion performance in the analysis. A new workflow is developed to assess and incorporate the damage mechanisms at the wellbore, fracture and reservoir into production forecasting. Currently, most reservoir models use a skin factor to represent the combined well damages mechanisms. The skin factor is adjusted based on the user's experience or data analysis instead of physical modeling. In this workflow, a detailed model is built to explicitly simulate the damage mechanisms, assess the dynamic performance of the well and completion with depletion, and generate a physics-based proxy function for reservoir modeling. The new workflow closes the modeling gap in production forecasting and provides insights into which damage mechanisms impact PI degradation.

In the workflow, a detailed model is built, which includes an explicit wellbore, an explicit fracture and the reservoir. Subsurface rock and flow damage mechanisms are represented explicitly in the model. Running the model with an optimization tool, the damage mechanisms’ impact on productivity can be assessed separately or in a combination. A physics-based proxy is generated linking the change in productivity to typical well parameters such as cumulative production, drainage region depletion and drawdown. This proxy is then incorporated into a standard reservoir simulator through the utilization of scripts linking the PI evolution of the well to the typical well parameters stated above. The workflow increases the reliability of generated production forecasts by incorporating the best representation of the near wellbore flow patterns.

By varying the damage mechanism inputs the workflow is capable of history matching and forecasting the observed field behavior. The workflow has been validated for a high permeability, over pressured deep-water reservoir. The history match, PI prediction and damage mechanism analysis are presented in this paper. The new workflow can help assets to: (1) history match and forecast well performance under varying operating conditions; (2) identify the key damage mechanisms which allows for potential mitigation and remediation solutions and; (3) set operational limits that reduce the likelihood of future PI degradation and maintain current performance.
Verification of Autonomous Inflow Control Valve Flow Performance Within Heavy Oil-SAGD Thermal Flow Loop
Authors: Taghavi Soheila , Aakre Haavard , Swaffield Steven , Brough R. Brent
Published: September 2019

One of the main challenges in Steam Assisted Gravity Drainage (SAGD) wells is steam breakthrough in producer wells, which can result in inefficient bitumen recovery due to high Steam Oil Ratio (SOR). Flow Control Devices (FCDs), also known as Inflow Control Devices (ICDs), have been developed for several years to balance the oil inflow along the horizontal wells and consequently delay or mitigate the unwanted fluid breakthrough. The newest generation of FCDs is a truly Autonomous Inflow Control Valve (AICV) which can optimize oil production, reduce SOR and significantly restrict the inflow of unwanted fluids such as water, steam and Non-condensable Gases (NCGs).

This novel AICV design was tested in a full-scale high temperature laboratory flow loop that replicates the downhole operating temperatures, fluid conditions and flow rates of a SAGD production well. The full-scale tests were conducted to determine how the AICV could optimize SAGD production by restricting the production of NCGs and steam and favor the production of oil.

Both single-phase and multi-phase flow performance behavior of the AICV are presented. Furthermore, the results are compared with a conventional passive ICD to illustrate the significant potential of the AICV in enhancing oil production, total recovery and overall project economics.

The results show that the production of lower temperature, relatively high viscosity oil can be increased by approximately 90% for the situation of deploying AICVs. Additionally, gas production is dramatically reduced from approximately 1200 L/h for the ICD, to 180 L/h with the AICV, corresponding to an 85% reduction. These results show that a considerable reduction in steam use is possible by using the AICVs, which would result in reduced energy usage for steam generation, reduced water usage, and reduced greenhouse gas emissions for each barrel of oil produced, thus improving the economics of SAGD projects.
Design and Engineering Implementation of Blowdown System for Cryogenic CO2- NG Pilot Facility
Authors: Md Jalil Abdullah Al , Mat Isa M Faudzi , Rostani Khairul , Othman Nurzatil Aqmar , M Shariff Azmi , Lau Kok Keong , Partoon Behzad , Tay Wee Horng
Published: September 2019

As easy gas resources around the world are depleting; high Carbon Dioxide (CO2) gas fields are thrust into the spotlight to become new candidates for field development. However, the presence of oftentimes sizable Carbon Dioxide contents in the gas reservoir (can be up to 80% volumetric) introduced a huge technical and economic challenges towards the field exploitation.

Over the last few years, several studies have been conducted on cryogenic technologies such as cryogenic distillation and supersonic nozzle in CO2 separation for fields containing more than 40% of CO2. Based on the studies, these new cryogenic technologies have shown to have high potential in separating CO2 from natural gas offshore to be utilized under carbon, capture, storage and utilization (CCUS) project.

The new cryogenic technologies are currently being tested for the proof of concept. Hence, a pilot plant, which is a scaled down version of the technology was developed. One of the major challenges faced during the pilot plant testing is the emergency depressurization philosophy as the process involves CO2 solids handling which is uncommon to the industry standard. Depressurization of high CO2 fluid at cryogenic temperature would lead to possibility of CO2 solids formation, hence potential blockage of process equipment and venting line.

Therefore, this paper will focus on the design of the pressure relieving system of such a facilities. It would also touched on the implementation of the pressure relieving system during the operation of the pilot tests and as well as the tests designed specially to test the pressure relieving system. Finally the paper would give a few proposals on improvements to be made to such system. It is also the ultimate aim of the authors and the team to introduce a new philosophy for Cryogenic CO2 Blowdown system to the process industry.
Oil Saturation in Residual Oil Zones and Its Effect on CO2 WAG Injection Strategies
Authors: Ren Bo , Male Frank , Wang Yanyong , Baqués Vinyet , Duncan Ian , Lake Larry
Published: September 2019

The objectives of this work are to understand the characteristics of oil saturation in residual oil zones (ROZs) and to optimize water alternating gas (WAG) injection strategies. ROZs occur in the Permian Basin and elsewhere, and operators are using CO2 injection for enhanced oil recovery (EOR) in these zones. ROZs are thought to be formed by the flushing effect of regional aquifer flow acting over geological time. Both the magnitude of oil saturation and the spatial distribution of oil differ from water-flooded main pay zones (MPZs).

We conducted flow simulations of CO2 injection into both synthetic and realistic geologic reservoirs to find the optimal injection strategies for several scenarios. These simulations of CO2 injection follow either man-made waterflooding or long-term natural waterflooding. We examined the effects of CO2 injection rates, well patterns, reservoir heterogeneity, and permeability anisotropy on optimal WAG ratios. Optimal is defined as being at minimal net CO2 utilization ratios or maximal oil production rates).

Simulations of CO2 EOR show that the optimal WAG ratio for the ROZs is less than 1 (ratio of injected water and CO2 in reservoir volumes), and it depends, but in qualitatively different ways, upon the well pattern and reservoir heterogeneity. The optimal WAG ratio tends to increase with changing from inverted 9-spot (80-acres) to inverted 5-spot (40-acre) or increasing reservoir heterogeneity. The ratios for ROZs are consistently less than those observed in the same geologic models experiencing CO2 injection after traditional (man-made) waterflooding. This is because the water saturation caused by slow regional aquifer flow (~1ft/yr) differs from that created by traditional waterflooding. In ROZs, water prevails almost everywhere and thus it is less needed to ease CO2 channeling as compared to MPZs.

This work demonstrates that optimal WAG ratios for oil production in ROZs are different from those in traditional MPZs because of oil saturation differences. Thus, commingled CO2 injection into both zones or directly copying WAG injection designs from MPZs to ROZs might not optimize production.
Wettability Studies and Estimation of Capillary Pressure on Heterogeneous Bioturbated Sandstones from Kachchh Basin, India
Authors: Dutta Adityam
Published: September 2019

Reservoir characterisation for modelling and flow simulation is done assuming the homogenous nature of the rock. Heterogeneity is overlooked to prevent occurrences of reserve management complexities. Bioturbated sandstone reservoirs are heterogeneous and prominently found in many petroleum producing basins. Studying the fluid characteristics of these heterogeneous systems is essential, as with changing characters will affect the resulting wettability behaviour. Thus, in a bioturbated heterogeneous reservoir, estimation of the wettability will help in estimating the flow behaviour and possible outcomes of hydrocarbon oil and gas recovery from such formations. With this background, a collective approach has been designed to understand the reservoir behaviour of bioturbated sandstones from Kachchh Basin. The samples are from outcrop, and the analysis includes established standard experimental procedures of core/rock analysis for estimating wettability. The paper explores the experimental analysis of the measuring contract angle in various bioturbated samples. Contact angles of both oil-wet and water-wet cores were measured considering time and gradient factors. Capillary pressure of the various grades of bioturbated sandstones was calculated combining obtained data on contact angle values along with the pore size (radius) and interfacial tension data. The results suggest that the final model can be designed and proposed for the characterisation of bioturbated heterogeneous sandstones using the Capillary pressure behaviour of rocks along with hysteresis trend of imbibition and drainage flows.
Mechanistic Modeling of MEOR as a Sustainable Recovery Technology: Coreflooding Validation, Sensitivity and Field Application
Authors: O. Ansah Eric
Published: September 2019

Globally, most oil fields are on the decline and further production from these fields is addressed to be practical in cost-effectiveness and oil productivity. Most oil companies are adopting two main technologies to address this: artificial intelligence and enhanced oil recovery (EOR). But the cost of some of these EOR methodologies and their subsequent environmental impact is daunting. Herein, the environmental and economic advantage of microbial enhanced oil recovery (MEOR) makes it the point of interest. Since, there is no need to change much-invested technology and infrastructure, amidst complex geology during MEOR application, it is entrusted that MEOR would be the go-to technology for the sustainability of mature fields.

Despite the benefits of MEOR, the absence of a practical numerical simulator for MEOR halts its economic validation and field applicability. Hence, we address this by performing both core and field- scale simulations of MEOR comparing conventional waterflooding. The field scale is a sector model(fluvial sandstone reservoir with 13,440 active grid cells) of a field in Asia - Pacific.

Here we show that pre-flush inorganic ions (Na+ and Ca2+) affect the mineralization of secondary minerals which influences microbe growth. This further influences carboxylation, which is relevant for oil biodegradation. Also, as per the sensitivity analysis: capillary number, residual oil saturation and relative permeability mainly affect MEOR. Secondary oil recovery assessment showed an incremental 6% OOIP for MEOR comparing conventional water flooding. Also, tertiary MEOR application increased the oil recovery by about 4% OOIP over conventional water flooding. It was established that during tertiary recovery, initiating MEOR after 5years of conventional waterflooding is more advantageous contrasting 10 and 15years. Lastly, per probabilistic estimation, MEOR could sustain already water-flooded wells for a set period, say, a 20% frequency of increasing oil recovery by above 20% for 2 additional years as highlighted in this study.
Wettability Alteration of Carbonates with Seawater and Higher Salinity Brines Explored Using a 3D Micromodel
Authors: Ro Grecia
Published: September 2019

We provide experimental evidence of wettability alteration using seawater salinity brine of an oil-wet system composed of a three-dimensional carbonate micromodel, crude oil, and connate-water brine salinity. We designed this procedure as a first step for evaluation of using seawater as an Improved Oil Recovery (IOR) agent. Our innovative design combines two main experimental best practices: micromodels, for repeatable experiments and X-ray computed tomography (CT) as a non-invasive technique for monitoring in situ fluid distribution. Both practices merge into a new three-dimensional micromodel set-up that uses only reservoir species (no high x-ray contrast chemicals).

Wettability alteration plays a key role to improve oil recovery from matrix blocks surrounded by water-invaded fractures in carbonate reservoir rocks. We designed a simple and replicable experimental apparatus and procedure to quantify contact angle distributions inside of porous media with a controlled level of heterogeneity in roughness and mineralogy. This experiment consists of visualizing the in-situ contact angle distribution of the aqueous phase inside a three-dimensional carbonate micromodel. Using Micro Computerized Tomography (MicroCT), we obtained three-dimensional images of fluid distribution with a voxel size of 3.8 microns.

We successfully studied the wettability state after connate water displacement and we also altered wettability of the carbonate porous medium from more oil wet to less water wet conditions. The water contact angle of the ganglia showed a 70% reduction in contact angle from an oil-wet to a water-wet system using an approximate seawater salinity and a 63% reduction in contact angle in the case of a full synthetic seawater. The initial average contact angles were 140° and 142° for the two solutions, respectively. After EOR seawater flooding, the average contact angle declined to 44° and 51°, respectively.
New Approaches of Porosity-Permeability Estimations and Quality Factor Q Characterization based on Sonic Velocity, Critical Porosity, and Rock Typing
Authors: Akbar Muhammad Nur
Published: September 2019

Many investigations have been discussed and it is a well-recognized fact that sonic wave velocity is not only influenced by its rock matrix and the fluids occupying the pores but also by the pore architecture details of the rock bulk. This situation still brings a lack of understanding, and this study is purposed to clearly explain how acoustic velocity and quality factor correlate with porosity, permeability and details internal pore structure in porous rocks.

This study employs 67 sandstone and 120 carbonate core samples collected from several countries in Europe, Australia, Asia, and USA. The measured values are available for porosity ϕ, permeability k, clay content Vcl, compressional velocity Vp, and quality factor Qp in saturated and pressurized conditions. Then, a proposed method is developed by re-arrangement on Kozeny equation to perform rock typing based on pore structure similarity which called as pore geometry-structure (PGS). The proposed rock typing method allows investigating the influential primary factors that control acoustic velocity and quality factor. Besides that, basic rock physics equations for sonic velocity and critical porosity concepts are also involved and derived to obtain a new solution to predict porosity and permeability.

At least eight rock groups are established from rock typing with its Kozeny constant. This constant is a product of pore shape factor Fs and tortuosity τ. Then, the relations of velocity and quality factor versus porosity, permeability, pore geometry (k/ϕ)0.5, and pore structure (k/ϕ3) are constructed. One can find that each relation among the rock groups of each lithology is clearly separated and produce high correlations. Velocity and quality factor tend to be high with an increase in Kozeny constant. However, for a given porosity for all the groups, velocity and quality factor increase remarkably with a decrease in Kozeny constant. These all mean that velocity and quality factor increase with either an increase in the complexity of pore systems or, at the same pore complexity, a decrease in specific internal surface area. On the other hand, each rock group for both sandstone and carbonate has its critical porosity and it strongly correlates with velocity and porosity. Finally, critical porosity becomes a specific property of rock groups having similar pore geometry and structure.

As a novelty, the empirical equations are derived to estimate compressional velocity and quality factor based on petrophysical parameters. Furthermore, this study also establishes empirical equations for predicting porosity and permeability by using compressional wave velocity, critical porosity, and PGS rock typing.
Review of Nanoparticle Applications in Petroleum Engineering: Recent Advancements and Challenges
Authors: Chauhan Prithvi Singh
Published: September 2019

This review is based on latest application of nanoparticles in hydraulic fracturing, and their feasibility as compared to other conventional methods. Focusing on technical, economic, mechanisms and direction of future research. Current status and advancement give a promising future application by using unique properties of nanomaterials such as small sizes, stability, magnetic properties and surface area which are yet to be exploited to full potential. Nano materials can be inculcated in drilling in all forms. From acting as additives in drilling mud there by enhancing density, gel breaking strength, viscosity, acting as a proppant, cross linking agent etc.

There are certain problems which are difficult to overcome using macro and micro type additives due to limitations in physical, chemical and environmental characteristics. Hence, the scientists are looking for such smart fluids which can overcome these limitations. Compared to their parent materials, nanoparticles can be modified physically, chemically, electrically, thermally, thermodynamic properties and interaction potential of nanomaterial. However more investment, work and pilot projects are required to understand properties of nanomaterials at reservoir temperature and pressure.

Nanomaterials such as aluminium oxide, zinc oxide, copper oxide, silicon dioxide, low cost carbon nanotubes, fly ash nanoparticles in unconventional reservoirs need to be further researched. Moreover, focus should be put on economic analysis, performance at reservoir conditions, cross linking and agglomeration properties, wettability alterations, interfacial tensions properties. The enhanced hydrocarbon recovery from unconventional reservoirs through wettability alterations and interfacial tension decrement by nanomaterials and combined use of fracturing fluid system comprising of VES, foams, proppants gives a promising future application.
Proactive Approach Minimizes Production Losses Due to Slug Flow
Authors: Carrie Sistrunk
Published: September 2019

When wells producing up casing in the Marcellus Shale dip into the slug flow regime, their production begins to drop off significantly. In some instances, wells that begin slugging dramatically can defer the majority of the production that they were delivering just months before slugging, resulting in significant loss in present value. To remedy this complication, engineers can install tubing in these wells to help lift fluids through the vertical section. Because slugging causes large fluctuations in production, most slugging is identified and addressed only after a production engineer notices these fluctuations. This can be months after the decrease in production rate.

To challenge this reactive approach to identifying wells ready for tubing installation, I created a workflow—implemented with software—to create a tubing installation schedule which requires little time or effort by the production engineer. While it is unlikely this program can be replicated exactly, the logic I used to create the program can certainly be adopted and applied elsewhere.

I used Coleman's model for critical rate to determine quantitatively when a given well is likely to begin to slug. Critical rate is defined as the minimum gas rate needed to maintain steady flow up a well to the surface. When the gas rate in a well dips below this critical rate, the well will dip into the slug flow regime. Bottomhole pressure (BHP) is a necessary input for the critical rate calculation. Because BHP data is not readily available for wells producing up casing, I had to create an alternative approach to determining BHP. After investigation, I determined that using data from different combinations of water-gas ratio (WGR), wellhead pressure (WHP), and gas rate allowed me to create a correlation to approximate the BHP of any given well on any given producing day. The resulting correlation could be incorporated in my workflow and—after combined with other input data—my software could determine, with sufficient accuracy, the critical rate of any given well on any given producing day.

An engineer can use my software to create a graph displaying both critical rate and gas rate with time for every well in a data set. Engineers can summarize the pertinent information from those plots in a data table which can assist them with creating a tubing installation schedule. This workflow will help engineers to determine more readily whether any of their wells are on the verge of slugging, allowing them to be more proactive in installing tubing on their wells and preventing costly deferred production.
Experimental Study of Gas-Liquid Diffusion in Porous Rocks and Bulk Fluids
Authors: Lou Xuanqing
Published: September 2019

The efficiency of miscible gas flooding relies on the mass transfer rate of species from one phase to another. Determining the diffusion coefficient of a gas-oil system is a critical factor to characterize this transfer phenomenon between gas and oil. Many gas-oil systems are being investigated to measure the diffusion coefficients, losing sight of the hindrance effect under reservoir conditions due to the pore network structure of porous media. Therefore, effective diffusion coefficients in porous media, which have more practical guiding significance, need further investigation. In this study, an experimental methodology based on the pressure-decay technique is proposed for capturing the gas-oil diffusion signals in porous rocks. A numerical model developed by our research group is implemented for estimating all diffusion parameters under different conditions. Results demonstrate the feasibility of this numerical simulation model. Experimental work and numerical simulation were performed on three different scenarios: gas-liquid diffusion in bulk Bakken oil, oil-saturated limestone and Bakken shale samples. The results present quantitative insight into the sensitivity of the diffusion coefficients to the degree of porous media restriction. Moreover, effective diffusion coefficients respond to pore network tortuosity, where more tortuous pore networks provide stronger hindrance effect on the molecular diffusion process. According to the results, this study can provide a technical support for correlating the effective diffusion coefficient to the relevant properties of rocks, which is helpful for establishing more accurate simulation models when the effective diffusion coefficients are missing.