bluuebunny/crossref_metadata_2025 huggingface dataset:
Surfactant/Polymer Flooding: Chemical-Formulation Design and Evaluation for Raudhatain Lower Burgan Reservoir, Kuwait
Authors: Al-Murayri M. T. , Hassan A. A. , AlAbdullah M. B. , Abdulrahim A. M. , Marlière C. , Hocine S. , Tabary R. , Suzanne G. P.
Published: October 2018

Surfactant/polymer (SP) flooding is an enhanced-oil-recovery (EOR) process that can lead to incremental oil recovery through two mechanisms: reducing oil/water interfacial tension (IFT) to decrease residual oil saturation and increasing the viscosity of the displacing fluid to improve overall sweep efficiency. IFT reduction allows better oil recovery by overcoming capillary effects, while the increased viscosity of the displacing fluid allows a more-homogeneous sweep of reservoir oil. Implementing chemical flooding in reservoirs with relatively high temperature and in-situ salinity (>200,000 ppm) is somewhat challenging. This paper describes the extensive laboratory work performed for the light-oil Raudhatain Lower Burgan (RALB) Reservoir (180°F/82°C) in Kuwait.

Reservoir fluids were thoroughly characterized to preselect the most-suitable chemicals for the SP process. Reservoir crude oil was analyzed and recombined with gases (C1 through C3) depending on the reported gas/oil ratio (GOR) to reproduce the oil in place (OIP) at original reservoir conditions in terms of pressure, temperature, and oil composition. A shift of the live-oil equivalent alkane carbon number (EACN) was compared with the dead-oil EACN.

Numerous surfactants were screened according to three main criteria: solubility in the envisioned injection brine, ultralow oil/water IFT, and chemical adsorption on reservoir rock. Different brine types were considered, and the use of adsorption inhibitors was also investigated. Furthermore, polymer screening involving temperature-resistant polymers was conducted by means of viscosity, long-term-aging, and adsorption tests. Polymer compatibility with the selected surfactants was also evaluated. The selected SP formulation was further evaluated through a series of coreflood experiments that were mainly dependent on chemical adsorption on reservoir rock and incremental oil recovery. An injection strategy was designed as a result of these experiments.

Laboratory results obtained thus far are encouraging and provide a systematic methodology to design SP injection in high-temperature, high-salinity, and light-oil reservoirs that are similar to the RALB reservoir. Additional technoeconomic evaluation is in progress in preparation for field-scale deployment of SP injection at RALB Reservoir.
An Experimental Study on Interactions Between Imbibed Fracturing Fluid and Organic-Rich Tight Carbonate Source Rocks
Authors: Liang Feng , Lai Bitao , Zhang Jilin , Liu Hui-Hai , Li Weichang
Published: October 2018

Carbonate reservoirs dominate oil (70%) and gas (90%) reserves in the Middle East, and imbibition is the main mechanism for fracturing-fluid uptake during the hydraulic-fracturing stimulation process. Because of the highly heterogeneous nature of tight carbonate source rocks, it is crucial to understand the effects of imbibed fluid on the mechanical, morphological, and flow properties of carbonate rocks. Although the influence of imbibed fluids on the wettability of carbonate reservoir has been studied extensively, research regarding the effects of imbibed fluids on the texture and mineralogy of carbonate rocks is still very limited. This paper aims to provide a conceptual approach and work flow to characterize and quantify microstructure and mineralogy changes in carbonate rocks caused by imbibed fluids.

A thin section of a low-permeability organic-rich carbonate-rock sample [7×7×0.3 mm (length×width×thickness)] was used in the study. The sample was submerged into 2%-KCl (pH = 7.1) fluid from one end to simulate the spontaneous-imbibition process. A scanning electron microscope (SEM) was used to capture the sample's morphological changes before and after spontaneous imbibition. Energy-dispersive-spectroscopy (EDS) maps were measured before and after fluid treatment to investigate changes in various elemental distribution. In addition, inductively coupled plasma (ICP) equipped with an optical-emission-spectrometer (OES) detector was used to quantify dissolved-ion concentration in the treatment fluid. Permeability and porosity were measured using core plugs with dimensions of 1.0×1.5 in. (diameter×length) before and after fluid treatment. During the imbibition process, approximately one-half of the sample was submerged in the treatment fluid.

The SEM images for the thin-section sample showed three zones with distinct fluid-uptake characteristics. In Zone I, which was fully submerged in the testing fluid, a significant amount of mineral dissolution was observed. In Zone III, which was above the testing-fluid level, considerable mineral precipitation was detected. While in the transition zone just above the water/air interface (Zone II between the previous two zones), only a minor level of mineral dissolution was observed. Elemental-distribution changes resulting from the fluid treatment were identified by EDS analysis in all three zones. Gypsum and calcite crystals dissolved into imbibed fluids upon reaction. Gypsum was found reprecipitated on the rock surface in the zones above fluid level. The observed gypsum formation likely resulted from the dissolution of the gypsum from the rock matrix, then reprecipitation later from the imbibition experiment caused by water evaporation. Absolute-permeability and porosity measurements for core-plug samples have shown that both were increased after the imbibition process.
Wellbore-Stability Analysis Considering the Weak Bedding Planes Effect: A Case Study
Authors: Mehrabian Amin , Pérez Arturo Díaz , Santana Claudia
Published: October 2018

Wellbore stability in shale is often hampered by the detrimental effect of existing weak bedding planes on shear failure of the rock surrounding the borehole. This paper presents results from an analytical solution to the wellbore-stress problem that incorporates rock failure along weak bedding planes. The solution is used for the case study of a highly inclined well section in a laminated layer of troublesome shale with a strike-slip faulting regime above the target formation in Latin America. Findings indicate improvement in the estimated margin for the wellbore-breakout limit of drilling-fluid density, and, more prominently, the safest drilling direction by accounting for the presence of weak bedding planes in the related wellbore-stability analysis.
Wellbore Modeling and Reservoir Characterization for the Application of Artificial Lift in Deep Horizontal Wells in the Unconventional Reservoirs
Authors: Pankaj Piyush , Patron Katherine Escobar , Lu Haidan
Published: October 2018

Several methods have been deployed for artificial lift in deep long horizontal wells completed in unconventional reservoirs. Some methods have been successful whereas some others have failed. In our study, we investigated the various lift mechanisms and derived an envelope for their application to such horizontal wellbores using a sensitivity study through a transient fluid- flow wellbore model.

A calibrated earth model from the Eagle Ford Shale basin with hydraulic fracture geometries in the horizontal wellbore was used for the sensitivity study. The wellbore profile was changed in the simulation model to four different types of profiles: toe up, toe down, toe up with hold trap, and toe down with hold trap. Other factors such as location of the artificial lift equipment in the wellbore, reservoir performance, and deliverability were considered for the deployment of the artificial lift method. Transient fluid-flow wellbore simulations and numerical reservoir simulations were used to determine the performance potential and effectiveness of the artificial lift mechanism for long-term productivity.

Multiphase fluid flow and transient flow phenomenon are critical modeling considerations for horizontal wellbores. It was found that the critical flow rate in horizontal wells can vary considerably when the well profile is considered. As the drilling dogleg severity increases, the chances of wellbore slugging and liquid holdup increase. Additionally, with producing time, the conditions change. In a gas lift well, if the gas injection rate is maintained above the critical rates as determined in this study, the production issues can be controlled. Therefore, it is clear from this study that the well trajectory and drilling uncertainty window must also account for the artificial lift method that is planned to be deployed. Adjustments to the artificial lift method placement in the wellbore would help offset negative impacts if the wells are poorly drilled.

Recommended practice for drilling, completion, and artificial lift can be derived from this study. Integration of the artificial lift selection to the earth model, drilling trajectory and landing, hydraulic fractures, and the completion model is paramount to improve the efficiency of artificial lift in the unconventional reservoirs.
Gas Lift Annulus Pressure
Authors: Decker Kenneth , Sutton Robert P.
Published: October 2018

Annulus pressure at depth is a primary requirement of any gas lift design. There are several methods of determining annulus pressure including reference to a monograph, density equation used to full depth with average pressure and temperature, and density equation used in small depth increments with average temperature and pressure within the increment. The choice of which method to use comes with limitations on the accuracy of the predicted pressure at depth.

When the annulus pressure at depth is calculated by use of a computer program, the choice of which correlation to use to model the critical properties of the gas and which compressibility factor correlation also affects the accuracy of the calculated pressure at depth.

As a gas lift well transitions from a geothermal temperature profile to a flowing temperature profile during the unloading and lifting process, the annulus pressure at depth will decrease even though the surface injection pressure remains unchanged.

Finally, the change in annulus pressure during the unloading process is governed by the volume of gas present in the annulus. A decrease in pressure is due to a reduction in gas volume. Traditional design techniques ignore this reality and substitute a theory of valve performance to explain annulus pressure changes during unloading. This simplified analogy of valve performance made it easy to design a gas lift well but incurred errors and misconceptions about how the annulus pressure changes during unloading.

This paper will address all of the above issues and provide advice on which method of annulus pressure prediction at depth is most appropriate for specific conditions, advise on the accuracy of the combination of different critical properties and compressibility correlations, offer an alternative design technique to account for changing annulus temperature during the unloading process, and finally, provide guidelines on how to accurately and realistically model the changes in annulus pressure during the unloading process.
Tuning VSDs in ESP Wells to Optimize Oil Production—Case Studies
Authors: Camilleri L. A. , Gong H.. , Al-Maqsseed N. H. , Al-Jazzaf A. M.
Published: October 2018

To maximize electrical submersible pump (ESP) uptime and production in North Kuwait's diverse reservoir conditions, it was necessary to combine variable speed drive (VSD) feedback control functionality with reservoir knowledge and real-time data and subsequently develop an operating strategy tailored to individual wells. The case studies in this paper show how well performance can be stabilized and production increased by incorporating motor current and downhole pressure into the VSD frequency control loop.

In North Kuwait fields, engineers studied wells with ESPs running in unstable condition or suffering frequent tripping due to underload or high temperature. Their ESP design datasheets, production test results, historical VSD running parameters, and downhole gauge data were used to calibrate pump and well performance models and identify the pump operating point. From these simulation results, the VSD feedback control loop function was optimized to minimize tripping and/or enhance stability, thereby increasing production.

The main causes of well instability and ESP downtime in North Kuwait are declining bottom hole flowing pressure and gas interference. The case studies illustrate how to select the appropriate VSD frequency feedback object function for each of these cases. For weak inflow, the VSD is configured to maintain constant intake pressure, especially where the intake pressure is less than 500 psia. For ESPs suffering from gas interference, constant current was implemented to avoid gas locking. The before and after results from the case study wells demonstrate the effectiveness of this technique for well stabilization and associated production increase. After the study, this method was implemented on 60 wells and resulted in a 21% reduction in the number of ESP trips over 6 months and an associated increase in uptime from 92% to 97%.

This case study describes a workflow that integrates ESP historical running data, reservoir knowledge, and VSD feedback control functions to increase well uptime by preventing ESP tripping. In addition, the workflow enhances ESP system operating stability and optimizes the reservoir drawdown, which offers the operator a viable option to achieve production objectives.
Quantitative Analysis of the Packer-Style Gas Separator Through Laboratory and Field Trials
Authors: Thompson Levins , Monk Alex , Oddie Gary
Published: October 2018

Projected gas production is a critical variable in well planning, and the downhole tools chosen for gas mitigation are vital to production performance. With sucker rod pumps, inefficiencies due to gas presence can reduce the time between pulls and negatively affect production rates. The packer-style gas separator (PSGS) has higher-liquid-volume capabilities than "poor-boy" gas anchor style tools. Packer-style gas separators have become an industry-recognized tool used to increase production in gaseous fluids on rod-lift wells by using volume restrictions to create pressure changes then filtering the free and entrained gases from liquids.

This study examines the operational parameters involved in the use of a PSGS in downhole gas separation. A flow loop laboratory test was conducted to evaluate the separator's qualitative properties. Additionally, two separate case studies were analyzed to understand the impacts of downhole gas separation on production rates, pump run time, and pump fillage.

The laboratory experiments used a transparent model in the flow loop for a visual analysis of the separation occurring during operation. A water-nitrogen solution of varying concentrations was run through the separator to examine drawdown parameters during inflow. The results showed that at 95% liquid capacity, the nitrogen inflow was successfully contained within the modeled tubing-casing annulus, preventing entry of gas into the simulated pump intake.

Two case studies were recorded in separate geographical regions to verify operational success. In south Texas, an operator successfully mitigated gas from five high-GLR wells. The PSGS in each well successfully separated 300 to 500 Mcf per day of gas from tubing production inflow. As a result, the total fluids output increased by up to 200%. In west Texas, an operator used the separator in nine different wells. On average, the fluid production increased by 61%, pump fillage increased by 11%, and pump run time increased by 33%.

Overall, through laboratory and field testing, the PSGS has proven its ability to handle a wide range of downhole conditions. By improving downhole gas separation before fluid enters the pump, gas interference effects are mitigated and overall rod lift system efficiency is enhanced.
One Company's Experience using Metal to Metal PCPs as the Primary Artificial Lift Method in a SAGD Operation
Authors: Becerra Oscar , Sheldon John
Published: October 2018

PetroChina Canada's Mackay River project is currently the largest SAGD operation where Metal to Metal PCPs (MMPCPs) are being used as the primary artificial lift method. Their simplicity and potential robustness in very high temperature applications were considered advantages in their selection for producing a reservoir that no other operator had developed before. Furthermore, their potential to reduce costs when converting wells from steam circulation to production was considered a key advantage over other potential forms of artificial lift. Subsurface monitoring was implemented to accelerate the learning curve and maintain optimum operating conditions for both the wells and the artificial lift systems. Real time data acquisition was used to track pump production performance and estimate wear within the MMPCPs over time.

At the time of this paper, 42 well pairs had been successfully converted from steam circulation to production, where 37 well pairs are actively being produced using MMPCPs. To date, 14 MMPCP system failures have occurred and an estimate of the downhole production system reliability is calculated. As well, Root Cause Failure Analysis investigations into three of the most common failure mechanisms are summarized. As the field is still in early stages of production, confidence in the reliability of the MMPCPs and understanding of the common failure mechanisms is expected to grow as more data becomes available.
Plunger Fall Velocity Studies in Vertical Wells
Authors: Acosta R.. , Pereyra E.. , Sarica C..
Published: October 2018

The objective of this study is to experimentally investigate the fall velocities of several type of plungers in various stagnant liquids and at different dynamic operating conditions. Six different plungers were evaluated, namely, new and used brush, new and used dual pad, new and used spiral, and new two piece type plungers. The experimental studies were carried out using two different facilities.

First, a simple plunger setup was used to measure the fall velocity of different plungers. This experimental configuration allows the use of different liquids at stagnant conditions (water, water with flowing air and oil). The experimental results show that plunger fall velocity in water is about 4% of the plunger velocity in air. Under a bubbling column and for all plunger types, the fall velocity fluctuates as the air passes through the plunger yielding, in some cases, an average velocity similar to the water case. The fall velocities in low and medium viscosity oils are 60% and 42% of the average velocity in water, respectively. Second, a comprehensive experimental facility was designed and constructed to study the plunger under dynamic operating conditions (or cycles) and at different fluid pressures (air). When the plunger fall velocity was studied under a cyclic operating conditions, the resultant fall velocity is about 60% of the velocity observed in only air, but 30 times larger than the corresponding velocity in stagnant oil.

Comparatively, the fastest conventional plunger is the spiral type, whereas the conventional sealing types (pad and brush) are the slowest ones. In addition, the effect of pressure is substantial and the fall velocity of the plunger rapidly decreases as the gas phase (air) pressure increases. Based on the experimental observations and data analysis, it was found that the fall velocity depends mainly on the type of plunger, air phase pressure, thickness of the liquid film on tubing wall, viscosity of the liquid, and density of the gas phase.

Plunger lift is one of the most used deliquification method for gas wells. However, only a few experimental studies have been found in the literature. None of them attempt the comparison of different plungers. This study present a new set of data that helps to understand the behavior of the different types of plungers.
A First Principles Model for Virtually Sensing Operational Parameters in an ESP Well
Authors: Aceros Egner , Camargo Edgar , Canelón José , Verde Alexander
Published: October 2018

The main challenges during the operation of electric submersible pumps (ESP) lifted wells include running the well at its optimal point, while honoring operational constraints posed by the production system, and extending the service life of the equipment. Overcoming these challenges will typically require building and continuously updating a model of the system. Now, due to issues such as high cost of sensors (including installation, calibration and maintenance), difficulty to reach the sensing point or lack of adequate technology, measuring some variables may be very hard or even impossible. An alternative is to develop a virtual sensor (model) to estimate unmeasured variables from measured values of other variables at different locations along the well. This work presents a model developed based on physical principles to accurately estimate key operational parameters of ESP lifted wells. The model comprises three differential equations that express the derivatives of pump flowrate, submergence level and well head pressure. Assuming as known the pump frequency, casing head pressure and production line pressure, these equations are solved numerically to estimate time profiles of submergence level, well head pressure, pump flowrate, pump intake pressure, pump discharge pressure and flowing bottomhole pressure. The model was instantiated and simulated for a particular ESP lifted well, and showed outstanding performance when estimating pump intake pressure and pump flowrate, as compared to a commercial simulator. The proposed virtual sensor exhibits high accuracy using a model with simplified equations, which can be executed quickly and reliably using few computational resources (processing time and memory); therefore, this sensor is completely suitable for direct installation in the ESP well (on a PLC or a RTU) for real-time monitoring, control and optimization. Other advantages of the proposed model include that it (i) reduces the required surface and bottomhole instrumentation, (ii) estimates the values of the variables during the transient between operating points, (iii) can be used to analyze the influence of operating parameters in the well behavior, without affecting production rate, (iv) incorporates a service factor to account for the equipment wear due to normal operation and (v) can be used in the implementation of optimization and control strategies.
Estimation and Analysis of Carbon Dioxide Friction Loss in Wellbore During Liquid/Supercritical Carbon Dioxide Fracturing
Authors: Li Xiaojiang , Li Gensheng , Sepehrnoori Kamy , Yu Wei , Wang Haizhu , Liu Qingling , Zhang Hongyuan , Chen Zhiming
Published: October 2018

The push to extend fracturing to arid regions is drawing attention to water-free techniques, such as liquid/supercritical carbon dioxide (CO2) fracturing. It is important to understand CO2 flow behavior and thus to estimate the friction loss accurately in CO2 fracturing, but no focus on CO2 friction loss in large-scale tubulars has been made until now. Because of the difficulty in conducting field-scale experiments, we develop a computational-fluid-dynamics (CFD) model to simulate CO2 flow in circular pipes in this paper. The realizable k-ε turbulence model is used to simulate the large-Reynolds-number fully turbulent flow. An accurate equation of state (EOS) and transport models of CO2 are used to account for CO2-properties variations with pressure and temperature. The roughness of the pipe wall also is considered. Our model is verified by comparing the simulation results with the experimental data of liquid CO2 and correlations developed for water-based fluid. It is confirmed that the friction loss of CO2 follows the phenomenological Darcy-Weisbach equation, regardless of the sensitivity of CO2 properties to pressure and temperature. The commonly used correlations also can give good predictions of the Darcy friction factor of CO2 within an acceptable tolerance of 4.5%, where the pressure range is 8 to 80 MPa, the temperature range is 250 to 400 K, the tubular-diameter range is 25.4 to 222.4 mm, and the Reynolds-number range is 105–108. Of all correlations used in this paper, the ones proposed by Colebrook and White (1937), Swamee and Jain (1976), Churchill (1977), and Haaland (1983) are recommended for field use. Finally, we investigate the influence of flowing pressure and temperature on Reynolds number, Darcy friction factor, and friction loss of CO2, and compare the difference between friction loss of water and of CO2 at different pressure, temperature, and flow-rate conditions.
Production-Performance Analysis of Composite Shale-Gas Reservoirs by the Boundary-Element Method
Authors: Wu Minglu , Ding Mingcai , Yao Jun , Li Chenfeng , Huang Zhaoqin , Xu Sinan
Published: October 2018

A shale-gas reservoir with a multiple-fractured horizontal well (MFHW) is divided into two regions: The inner region is defined as stimulated reservoir volume (SRV), which is interconnected by the fracture network after fracturing, while the outer region is called unstimulated reservoir volume (USRV), which has not been stimulated by fracturing. Considering an arbitrary interface boundary between SRV and USRV, a composite model is presented for MFHWs in shale-gas reservoirs, which is based on multiple flow mechanisms, including adsorption/desorption, viscous flow, diffusive flow, and stress sensitivity of natural fractures. The boundary-element method (BEM) is applied to solve the production of MFHWs in shale-gas reservoirs. The accuracy of this model is validated by comparing its production solution with the result derived from an analytical method and the reservoir simulator. Furthermore, the practicability of this model is validated by matching the production history of the MFHW in a shale-gas reservoir. The result shows that the model in this work is reliable and practicable. The effects of relevant parameters on production curves are analyzed, including Langmuir volume, Langmuir pressure, hydraulic-fracture width, hydraulic-fracture permeability, natural-fracture permeability, matrix permeability, diffusion coefficient, stress-sensitivity coefficient, and the shape of the SRV. The model presented here can be used for production analysis for shale-gas-reservoir development.
A Practical Methodology for Production-Data Analysis of Single-Phase Unconventional Wells With Complex Fracture Geometry
Authors: Chen Zhiming , Liao Xinwei , Zhao Xiaoliang
Published: October 2018

Forecasting coalbed-methane well performance in the Qinshui Basin is a key task for predicting future gas production. There is evidence suggesting that complex fracture geometry and multiple hydraulic-fracture networks might develop. Unfortunately, very limited work has been published on the production analysis of multiple-fractured vertical wells (MFVWs) in coalbed-methane reservoirs. To better understand the production performance of the MFVWs, a new, fast, and reliable methodology is presented in this paper. This semianalytical methodology is derived from an analytical reservoir solution and a numerical fracture solution. Dual-porosity, gas-diffusion, gas-adsorption, and stress-sensitivity effects are considered. Verification of the methodology is accomplished through comparison with synthetic-reservoir-simulation cases and with field-performance data. Good agreement is shown between results from the proposed methodology and those from a reservoir-simulation model. Results from this study indicate increasing transient-gas-production rate and cumulative gas recovery with increasing natural-fracture permeability, gas-storage coefficient, Langmuir volume, fracture conductivity, and fracture length. The transient gas-production rate and cumulative gas recovery were found to decrease with increasing stress-sensitivity coefficient. The parameters found to have the strongest and weakest effects on the gas-production rate were the natural-fracture permeability and the fracture conductivity, respectively. Results from this study on MFVWs in coalbed-methane reservoirs indicate fracture length is more important than fracture conductivity in terms of its effect on gas productivity.
The Effect of Voidage-Displacement Ratio on Critical Gas Saturation
Authors: Kim Tae Wook , Kovscek Anthony R.
Published: October 2018

The critical gas saturation in permeable sands was studied as a function of depletion rate and the presence of an aqueous phase as the major experimental variables. Voidage-replacement ratios (VRR = injected volume/produced volume) less than 1 were used to obtain pressure depletion with active water injection. Three different live crude oils were considered. Two of the oils are viscous Alaskan crudes with dead-oil viscosities of 87.7 and 600 cp, whereas the third is a light crude oil with a dead-oil viscosity of 9.1 cp. The critical gas saturation for all tests ranged from 4 to 16%. These values for critical gas saturation are consistent with the finding that the gas phase displayed characteristics similar to those of a foamy oil. For a given oil and depletion rate, the critical gas saturation was somewhat larger for VRR = 0 than it was for VRR = 0.7. The oil recovery correlates with the critical gas saturation (i.e., for a given VRR, tests exhibit greater oil recovery when the critical gas saturation is elevated). For the conditions tested, there was not a strong correlation of critical gas saturation over more than two orders of magnitude of the rate of pressure depletion, for a given VRR. Such behavior might be consistent with theoretical studies reported elsewhere that suggest that the critical gas saturation is independent of the pressure-depletion rate when the rate of depletion is small.
Heavy Oil Extraction in Texas with a Novel Downhole Steam Generation Method: A Field-Scale Experiment
Authors: Hascakir Berna , Noynaert Sam , Prentice J. Andrew
Published: October 2018

Heavy oil extraction requires heat introduction to the reservoir to enhance the mobility of oil. While steam injection is one of the most reliable thermal EOR methods for heat introduction, it has several operational, technical, economic, and environmental limitations. This study investigates the effectiveness of a newly developed downhole steam generator which not only minimizes the heat losses due to distance the between generation and injection but accomplishes oil production with lower steam and energy requirements. A test of the downhole steam generator took place in a small 20 acre area northeast Texas with 13 wells accessing a shallow (540 feet TVD) heavy oil bearing sandstone. The viscosity and API gravity of the heavy oil was reported as 3,000 cP at 100 °F and 19 °API. The initial oil and water saturation were approximately 65% and 35% respectively.

Steam injection was started in April of 2013 at steam rates of up to 1300 bbl/day of 600°F steam, producing a total of 540 million BTU per day. The steam front was carefully monitored with temperature readings through oil sampling, both on an individual well basis. According to the temperature readings, steam front movement was faster than typical steam flooding cases in such high viscosity oil reservoirs. Preferential steam propagation occurred towards the northwest of the field due to reservoir dipping towards the southeast. The oil production increased on both the 20 acre test site and wells outside of the test site. The varying distances between injection wells and production wells enabled us to observe steam propagation at varying length. Thus, we could acquire produced oil sampling at varying steam exposure times at different locations and depths. Viscosity, density, and compositional analyses were carried out on the produced oil samples. It has been observed that the viscosity and density of produced oil were not improved due to emulsion formation which is a common concern for any steam injection project. However, further analysis revealed that emulsion breaking is possible with the use of asphaltene insoluble solvents or cationic surfactants. Since the novel design of the downhole steam generator allows injection of any additional chemical with steam during the process, these chemicals could be added to the steam stream to enhance the effective steamed area and reduce the flow assurance related problem. The new downhole steam generation tool provides an opportunity to generate steam in-situ and co-inject steam with additional chemicals to prevent emulsion formation and asphaltene precipitation. Thus, this study proves that downhole steam generation can be feasible for heavy oil extraction, even for small, low-rate fields, if all drawbacks (such as emulsion formation and asphaltene precipitation) are considered and the chemicals injected with steam are selected properly.
Data-Driven In-Situ Geomechanical Characterization in Shale Reservoirs
Authors: Li Hao , He Jiabo , Misra Siddharth
Published: October 2018

Compressional and shear travel time logs (DTC and DTS) acquired using sonic logging tools are crucial for subsurface geomechanical characterization. In this study, 13 ‘easy-to-acquire’ conventional logs were processed using 6 shallow learning models, namely ordinary least squares (OLS), partial least squares (PLS), elastic net (EN), LASSO, multivariate adaptive regression splines (MARS), and artificial neural network (ANN), to successfully synthesize DTC and DTS logs. Among the 6 models, ANN outperforms other models with R2 of 0.87 and 0.85 for the syntheses of DTC and DTS logs, respectively. The 6 shallow learning models are trained and tested with 8481 data points acquired from a 4240-feet depth interval of a shale reservoir in Well 1, and the trained models are deployed in Well 2 for purposes of blind testing against 2920 data points from 1460-feet depth interval. Following that, 5 clustering algorithms are applied on the 13 ‘easy-to-acquire’ logs to identify clusters and compare them with the prediction performance of the shallow learning models used for log synthesis. Dimensionality reduction algorithm is used to visualize the characteristics of the clustering algorithm. Hierarchical clustering, DBSCAN, and self-organizing map (SOM) algorithms are sensitive to outliers and did not effectively differentiate the input data into consistent clusters. Gaussian mixture model can well differentiate the various formations, but the clusters do not have a strong correlation with the prediction performance of the log-synthesis models. Clusters identified using K-means method have a strong correlation with the prediction performance of the shallow learning models. By combining the predictive shallow learning models for log synthesis with the K-means clustering algorithm, we propose a reliable workflow that can synthesize the DTC and DTS logs, as well as generate a reliability indicator for the predicted logs to help an user better understand the performance of the shallow learning models during deployment.
Predicting Sand Production in HPHT Wells in the Tarim Basin
Authors: Wang Haotian , Yang Xiangtong , Zhang Wei , Sharma Mukul M.
Published: October 2018

The objective of the study is to determine the main mechanisms for sand production and to propose completion designs to minimize sand production for HPHT gas wells in the Tarim Basin. Sand production has been a very serious concern in these HTHP gas wells. This paper presents field results for several key wells which are prone to sanding and investigates the possible reasons and mechanisms responsible for sand production. A fully coupled 3D, poro-elasto-plastic sand production model has been developed and applied to study sand production issues for these wells. Sand production data from several wells were analyzed to better understand the conditions under which sand production occurs and conditions under which it is mitigated.

The sand production model was used to model the different completion designs and flow back strategies that were used in the field. The model couples multi-phase fluid flow and elasto-plasticity to simulate pressure transient and rock deformation during production. The sanding criterion is a combination of both mechanical failure (shear/tensile/compressive failure) and fluid erosion. A novel cell removal algorithm has been implemented to predict the dynamic (time dependent) sand production process. In addition, the complex geometry of the wells and perforations are explicitly modeled to show cavity propagation around hole/perforations during sand production.

For this study, triaxial tests on core samples have been conducted and the stress-strain curves under different confining stresses are analyzed to obtain rock properties for both the pre-yield and post-yield period. The wells were categorized into ones that had massive sand production and ones that showed much less sand production. Operational and mechanical factors that were empirically found to result in sand production were identified. The sand production model was run to verify the role played by different factors. It is shown that completion design, rock strength and post failure behavior of the rock are key factors responsible for the observed sanding in these wells. In addition, the drawdown strategy and the associated BHP change and the extent of depletion play an important role in the sanding rate. Several strategies for minimizing sand production are suggested for these wells. These include, drawdown management, completion and perforation design. In this study, we quantitatively show for the first time that data from HPHT gas wells that suffer severe sand production problems can be modeled and analyzed quantitatively to determine the mechanisms of sand production. This allows us to make operational recommendations to minimize sanding risk in these wells.
A New Geochemical Logging Tool for Determination of Formation Chemistry and Mineralogy in both Conventional and Unconventional Reservoirs
Authors: Pemper Richard , Pereira Alex , Hou Guojing , Dolliver Darrell , Tudge Joanne , Kharrazi Jennifer , Chok Hamed , Schmid Gregory , Mekic Natasa , Blankinship Tom , Epstein Robert , Cave Tim , MacPherson Adam
Published: October 2018

A new geochemical logging tool has been designed and developed for the precise determination of formation chemistry, mineralogy, and lithology, as well as the identification of total organic carbon (TOC). The primary elements identified by the system include aluminum, calcium, carbon, chlorine, hydrogen, iron, magnesium, oxygen, potassium, silicon, sulfur, thorium, titanium, and uranium. These elements are utilized to identify the minerals present in both conventional and unconventional formations.

Tool operation begins by emitting high energy 14 MeV neutrons into the formation from a pulsed neutron generator, and the resulting gamma rays are intercepted by a high resolution, state of the art, LaBr3(Ce) detector. In order to exclude background gamma rays and provide a clean capture spectrum, a boron coating has been placed on the housing. The 3.25-inch tool diameter makes the system easier to operate in small boreholes as well as in horizontal wells.

The extensive set of detected elements is made possible by the PNG, where high speed electronics are incorporated to accrue both capture and inelastic energy spectra. A Levenberg-Marquardt matrix inversion algorithm is employed to separate the spectra into their fundamental elemental components. Characterization of the system has been achieved through numerous measurements in more than 30 formations from a newly constructed Rock Formation Laboratory in Fort Worth, Texas as well as at the Callisto Facility in the United Kingdom. A significant number of core samples were obtained from these formations and analyzed for elemental and mineralogical composition. Extensive use of MCNP modeling was exploited for the design and characterization of the system.

The final lithological and mineralogical interpretation is guided by the elemental concentrations of the various elements, as well as the computation of intrinsic sigma. Magnesium is used to differentiate between calcite and dolomite in carbonate formations. Aluminum, iron, and potassium, in addition to silicon, provide the information required to distinguish the various clays in sand/shale formations. Sulfur is vital for the identification of both pyrite and anhydrite. Ternary plots are generated to aid in the final interpretation. To demonstrate the effectiveness of this work, log examples from the field are provided.
Permanent P&A Design - What is Good Enough?
Authors: Arild Øystein , Lohne Hans Petter , Nielsen Mariann , Moeinikia Fatemeh , Selvik Jon Tømmerås , Abrahamsen Eirik Bjorheim , Ford Eric Patrick , Mansouri Majoumerd Mohammad
Published: October 2018

Recently, there has been a drive towards a risk-based approach to plug & abandonment (P&A) design. To apply a risk-based approach for decision-making, i.e. to decide if a P&A design is acceptable or not, risk acceptance criteria have to be established and be approved by authorities. This paper presents the core of a risk-based approach, and then present three alternative risk acceptance criteria based on leakage risk of permanently plugged and abandoned wells.

The core elements of the risk-based approach for evaluation of the containment performance in permanently plugged and abandoned wells consist of estimating probability of leakage and associated leakage rates for any proposed P&A design. These will then have to be used to evaluate the acceptability of the design, by comparing them to some defined acceptance criteria. Different principles can be followed to define such criteria, such as being consistent by accepting risk levels which have been considered acceptable in other situations, environmental survivability or considering the cost-benefit to optimize the allocation of funds.

The approach and principles used are described and applied in the context of P&A design. Based on the specification of an actual gas producing well that was permanently plugged and abandoned on the Norwegian Continental Shelf (NCS), a synthetic case study is established. Simulations are carried out to provide estimations of the core elements of the risk-based approach, i.e. leakage rate and probability of the leakage, for the synthetic case. Three examples of risk acceptance criteria are then presented and discussed. The estimations derived from simulations for the synthetic case study are used to exemplify the strengths and weaknesses of the three acceptance criteria.
Applicability Criteria for Subsea Developments: A Study on the HSE Aspects, Technical Limits, Commercial Constraints, and Other Non-Technical Factors to be Discussed while Framing and Sanctioning a Subsea Project
Authors: Beltrami Francesco
Published: October 2018

The persistence of the current downturn of the subsea industry offers the opportunity to rethink the reasons of the success of subsea and deepwater projects over the past two decades to (a) identify where and how subsea technologies can be effectively used to create value for an operator, and (b) which are the subsea applicability limits, either real or perceived, that may suggest opting for a different field development concept.

This paper discusses the definition and use of the applicability criteria for subsea developments. Further to a brief methodology note, these criteria are then used to map, in a qualitative way, different situations where a project may benefit from the adoption of subsea technologies.

HSE aspects, technical limits to the required technologies, commercial constraints, profitability during field life, effectiveness of hydrocarbons recovery and other non-technical factors (from human error to geopolitics) are illustrated and arranged into a logical, clear frame to map the proposed applicability ranges for subsea developments.

The applicability maps are then employed to briefly discuss some significant aspects of the booming success of the subsea industry from its first ‘golden age’ (1999-2014) and also a few issues and challenges that deserve some attention while preparing for the next subsea and deepwater ‘boom’.
Implementation of a Fully Automated Real-Time Torque and Drag Model for Improving Drilling Performance: Case Study
Authors: Shahri Mojtaba , Wilson Timothy , Thetford Taylor , Nelson Brian , Behounek Michael , Ambrus Adrian , D’Angelo John , Ashok Pradeepkumar
Published: October 2018

The drilling industry has made significant progress on physics-based torque and drag (T&D) models that can run either offline (pre-job or post-job) or in real-time. Despite its numerous benefits, real-time T&D analysis is not prevalent since it requires merging real-time and contextual data of dissimilar frequency and quality, along with repeated calibration whose results are not easily accessible to the user. Our goal is to implement a rig-based T&D advisory system which overcomes these obstacles.

The first step towards real-time T&D analysis is a reliable data acquisition and processing system at the rig site. This includes the ability to receive and process data of different frequency and merge it with contextual data. Once this was accomplished, the system was implemented on more than 20 rigs in North America. We then adopted a soft-string T&D model to be used for various purposes including the automatic detection of overpull/underpull events and the depths where these occur, open-hole and casing friction factor determination, sensor calibration and real-time broomstick plotting and field data comparison for subsequent casing run design.

In this paper, we demonstrate the field and office application and usage of a real-time T&D model. The system on which the model is run must be able to merge both real-time (hook load, torque, rig state, etc.) and contextual (BHA composition and specifications, wellbore design and trajectory, mud weight, etc.) data. Given the developed infrastructure, the drilling engineers have access to automated model calibration in real-time which enhance the reliability and repeatability of results and also contribute to time/cost savings. Using the embedded rig state identification engine, different real-time data points can be classified (e.g., slack-off, pick-up and rotating off-bottom) and used in T&D calibration. In addition to traditional broomstick plots, the algorithm uses probabilistic data analytics approaches to identify troublesome zones (e.g., overpull/underpull locations). In a fully automated manner, the platform generates predictions based on calibrated friction factors to enhance subsequent casing run as well. The outputs are used in both field and office in a variety of ways to improve drilling performance and safety.

Using the developed platform, we automated the process of T&D analysis and reduced/eliminated the time/cost required to run physical models offline. Using data from multiple BHA runs and one casing run from an exemplary well in North America, we were able to demonstrate the benefits of the automated real-time application in comparison to the traditional offline use of torque and drag analysis.