bluuebunny/crossref_metadata_2025_split huggingface dataset:
Distributed Pressure Sensing for Production Data Analysis
Authors: Assiri Wisam , Uzun Ilkay , Ozkan Erdal 
Published: March 2019

Abstract
Well testing is an essential tool to estimate reserves and forecast production. The assessment depends on the analytical solution of the continuity and diffusivity equations which results in average reservoir properties. The key challenge is to acquire real-time data of pressure pulse signatures as they propagate and reach the boundaries. A potential solution is to use a permanent downhole pressure gauge or an array of distributed pressure sensors (DPS) placed at each hydraulic fracture cluster to characterize the flow. This work presents the elements of an innovative analytical model that uses this data to derive formation properties, visualize averaged flow dynamics, and evaluate the Stimulated Reservoir Volume (SRV).
The real-time distributed pressure data, together with flow rate history, provides information that can be used to characterize the flow and estimate the boundary effect of hydraulic fractures and fissures. First, the numerically generated synthetic data is analyzed at each cluster to eliminate pressure drops due to friction. Next, analytical solutions of the continuity equation as well as trilinear models are used to invert reservoir properties to verify the proposed model. Based on the results, an advance statistical analysis is used to characterize the contribution of each variable to the flow rate.
The numerical results suggest that there are key variables to identify different flow regimes. Numerical simulations are used to gauge the accuracy of the analytical model at predicting reservoir properties and flow patterns. Statistical analysis evinces that there are key parameters of the formation, fractures, and fissures that control the well productivity. The numerical analysis showed that for every reservoir type there are different combination of fracture parameters that can optimize the flow. Moreover, the results describe a method to obtain hydraulic fracture properties around each pressure sensor (DPS) and forecast their productivity. Finally, statistical learning was investigated as a potential solution to derive reservoir properties, including hydraulic and natural fractures, using the pressure pulse signature data without the need of inversion.
The results show that there are key parameters that determine flow patterns. The importance of the accurate recognition and analysis of the multiple linear flow regimes at each cluster is in the potential to estimate the size of the SRV around hydraulic fractures during the transient life of the well. Moreover, this paper explains the procedure used for analyzing the change in the flow rate to obtain reservoir properties.
Evolution of Frac Plug Technologies – Cast Iron to Composites to Dissolvable
Authors: Walton Zachary , Fripp Michael , Porter Jesse , Vargus Greg 
Published: March 2019

Abstract
A technological revolution in hydraulic fracturing has occurred between early wellbore stimulation techniques and present day stimulation that has reduced cost and increased stimulation performance. Part of this revolution has been driven by the improved technology of frac plugs. This paper discusses how the evolution from cast iron frac plugs to composite plugs, then later to an interventionless stimulation completions process has enabled stimulation in extended-reach wellbores.
Drillable frac plugs were initially created from cast iron. Although cast iron plugs met run-in requirements and pressure ratings, the time required to remove these plugs by milling was long. Composite frac plugs were developed to accelerate the mill-out process. The light weight of the composite frac plugs also enabled the frac plugs to be run into a horizontal section of the wellbore. This operational change, combined with the ease of milling the composite plugs, has paved the way for the horizontal completion market for the past 15 years. However, the use of composite frac plugs in extended-reach horizontal wells was limited by the need to drill out the plugs. The development of dissolvable frac plugs eliminated the need to drill out the plugs allowing operators to produce wells much sooner. This elimination of the drill-out step for dissolvable frac plugs has also enabled the successful completion of extended-reach horizontal wells which may be beyond the practical range of coiled tubing or jointed tubing.
The need for efficient production in extended-reach wellbores has spurred the continuing evolution of hydraulic stimulation. This paper describes 20 years of new technology and field results to document the changes to the design and construction of frac plugs, as well as changes to the design and operation of the wellbore.
Water-Alternating-Weak Gel Technology and its Application in High Water Cut Oil Reservoir in Bohai Oilfield
Authors: Liu Yigang , Li Yanyue , Zhang Yunbao , Li Hui , Xue Baoqing , Wang Nan , Lu Xiangguo , Dai Leiyang , Xia Huan , Xie Kun 
Published: March 2019

Abstract
NB oilfield, as the one of typical blocks of the Bohai Oilfield, is a heavy oilfield with an oil viscosity of 413~741mPa·s. Therefore, when injecting water, water channeling of production wells is very serious. As a regular and useful technology to control mobility, weak gel flooding has been used in NB oilfield since 2005, which increased by oil production up to 110,000 cubic meters. However, this technology usually results in inefficient displacement of weak gel in the late injection stage because of growing of high permeability layer. The field test documents show that the suction profile has reversed in 2015 since water entry ratio in low permeability layers decreases from 26.2% to 12.4%. Correspondingly, oil wells have tiny water cut decrease range and product polymer as high as 400 mg/L.To improve the above disadvantage of weak gel flooding in the late development stage, laboratory experiments are carried out firstly to verify water-alternating-weak gel to adjust profile inversion. The experimental results show that the reversal time of profile is delayed from 0.8 PV to 1.35 PV and water entry ratio in low permeability layer increases by 13% ~ 27%, obtaining oil recovery rise by 1.7%~4.6%. It indicates that water-alternating-weak gel technology can adjust and balance resistance in high and low permeability layer by designing different size of weak gel slug. Based on the laboratory experiment, during the period from 2016 to 2017, we conducted field applications in three well groups in NB oilfield. The weak gel was first injected for one month, followed by water injection for one month, which was repeated for a total of 8 times. Compared with the continuous flooding of weak gel, the total agent dosage decreases by 51%, the oil production efficiency ratio increases from 40% to 100%, and the oil production increases from 18,226 square meters to 40,745 square meters. Moreover, the profile test of NB17 well showed that water entry ratio in low permeability layer increases from 12.4% to 27.26%, resulting in water cut of corresponding production well declined from 54% to 32%. Our research validates that water-alternating-weak gel technology can improve water entry profile in the late stage of gel flooding and provide a new reference for the development of heavy oil resources in Bohai Oilfield of China.
Production Optimization Challenges and Solutions for Heavy Oil - North Kuwait
Authors: Bassam Abdul-Aziz , Al-Besairi Ghazi , Al-Dahash Sulaiman , Sierra Tomas , Mohamed Assem , Heshmat Kareem 
Published: March 2019

Abstract
The demand for digital oil field solutions in artificially lifted wells is higher than ever, especially for wells producing heavy oil with high sand content and gas. A real-time supervisory control and data acquisition solution has been applied in a large-scale thermal pilot for 28 instrumented sucker rod pumping wells in North Kuwait. This paper focuses on the advantages of real-time data acquisition for identifying production-optimization candidates, improving pump performance, and minimizing down time when using intelligent alarms and an analysis engine.
Real-time surveillance provided a huge amount of information to be analyzed and discussed by well surveillance and field development teams to determine required actions based on individual well performance. Controller alarms and intelligent configurable alarms in one screen enabled early detection of unexpected/unwanted well behavior, re-investigating well potential, and taking necessary actions.
The challenge was to handle heavy oil, sand, and gas production, maintain all wells at optimum running conditions before and after steam injections, and take into consideration the effect that injections would have on nearby wells.
Recording in the database a "tracking item" for each well event enabled review and evaluation of the wells and creation of optimization reports. The daily, 24-hour surveillance of the wells resulted in observing common problems/issues on almost all wells and other individual issues for specific wells.
The following are examples of problems identified in early stages: Detected wells with gas interference before they reached gas lockDetected wells with high flowline pressure before flowline blockage resulted from sand productionDetected wells with standing valve and/or traveling valve leak—resulting from sand production—before the pump stuck
The availability of such a supervisory control and data acquisition (SCADA) system helped in guiding the operations team to further investigate only specific items from the field side to confirm the findings. The ability to remotely control the wells and remotely change configuration of the variable speed drive parameters enabled instant implementation and continuous production optimization. The powerful SCADA solution enabled creating short- and long-term plans and monitoring the behavior of wells while the implementation phase was executed.
For the first time in South Ratqa in North Kuwait, the smart field approach was implemented in a thermal pilot using sucker rod pumps; and the results will be used as a reference for the upcoming projects in this area. Real-time monitoring and data storage in a single database with an analysis engine provided fully automated surveillance and the capability of remotely controlling and applying required actions for production optimization.
Effects of Reservoir Connectivity with Underlying Mauddud Reservoir and Sand Distribution on Developing Wara Reservoir in the Bahrain Field
Authors: Nemmawi Nadia , Michael Dowen , BuAli Yusuf 
Published: March 2019

Abstract
The sandstone facies of Wara formation designated as Ac zone in the Bahrain Field belongs to the Wasia group of the Middle Cretaceous age.
The reservoir has been characterized in three distinct geographical areas of sand distribution based on varied depositional systems, resulting in sands with differing orientation, texture and thickness. The reservoir varies in thickness between 5 and 60 ft and is composed of a series of discontinuous high porosity, high permeability sandstone lenses, sealed above and below by thick competent marine shales.
This paper addresses the variability of the reservoir and the connectivity with the underlying Mauddud reservoir which consequently determined the drive mechanisms.
The original oil in place of Wara sandstone was calculated deterministically using a 3D geological model and incorporated both Geophysical and Petrophysical models. Initial water saturation was calculated from capillary pressure data with net sand cut offs applied. The discontinuity of the sands has resulted in individual sand bodies with variable oil water contacts. Thinner sand bars and channels in the northern area of the Bahrain Field produce by depletion drive. Juxtaposition with the underlying Mauddud reservoir occurring across the faults allows communication with Mauddud gas cap in the Central area which results in the gas drive. Water drive is the main mechanism in the South channel.
Recent log data acquired from new wells has improved our knowledge of this reservoir and explains the different oil-water contacts with the varying drive mechanisms. This improved understanding has resulted in a new development strategy to maximize recovery with infill drilling and possibly Enhanced Oil Recovery (EOR).
Measuring Fracture Network Pressures During Fracturing and Production in Unconventionals in Saudi Arabia
Authors: Rueda Jose , Valbuena Jose , Baki Sohrat , Mechkak Karim , Mohannad Mahfouz , Momin Ali , Mulhim Nayef 
Published: March 2019

Abstract
There is little understanding on how the fracture networks in unconventional source plays, commonly referred as Stimulated Reservoir Volumes (SRV), grow with distance and time during the fracturing jobs and connect other offset laterals with or without hydraulically created SRVs. Understanding of this connectivity with offset wells helps on defining the distance among the laterals to avoid any potential negative impact during fracturing and production.
In Jafurah field, several pads have been used to monitor pressures during the fracturing jobs (crosslinked, hybrids and slickwater) and flowbacks. This provides a unique way of measuring the fracturing network pressures at different distances for the initial life of the wells, starting from the generation of the fracture system up to pressures responses due to the production of offset wells.
This paper summarizes the layout and technologies used in a series of pads to understand the connectivity among the wells. Bottom-hole and surface pressures were collected during frac and production in the pads. Also, the outer wells on the pads were monitored from offset contiguous pads. Once the pressure data was synchronized in the different events during fracturing, pressures are plotted to determine the level of pressure disturbance with time. Simultaneously, the absolute values are compared with the minimum stresses, re-opening pressures of natural fractures, and the vertical stresses from the area to determine if the fracture network is reaching the monitor wells and stimulating them. Pressures and derivative behavior are also plotted during the production of the offset wells, to see the level of interference during the initial production, and how the intensity changes as function of time.
It was observed in all the pads that pressures in the monitor wells during the fracturing jobs have four periods: 1) no pressure disturbance is observed (compressibility effects); 2) pressure slowly increases up to equivalent minimum stress (closure pressure); 3) pressure continues increasing from the minimum horizontal stress up to re-opening pressure of the natural fracture systems; and 4) pressure stays above the natural frac re-opening pressure but below the vertical stresses (overburden). It can be seen that pressures in the monitor wells present a cumulative effect, suggesting a generation of fracture systems all hydraulically communicating. This paper will present the different levels of interference observed in the pads as a function of frac types, distance to the monitor wells, and existence of hydraulic fracture in the monitor area. The methodology can investigate interference in unconventional wells during the fracturing treatments and production. This approach will help in understanding how the fracture networks in unconventionals grow and connect to other offset wells.
Continuous Proportional Steering for a Re-Entry Multi-Lateral Well in Cretaceous Reservoir in UAE Saves Rig Days and Achieves Reservoir Contact Objectives in a One-Bit Run
Authors: Adams Adeniyi A. , Soliman Ahmed M. , Deng Lichuan , Jurdi Imad , Al Hosani Mohamed Salem , Al Menhali Adnan , Ardila Jose David 
Published: March 2019

Abstract
The challenge was to achieve more reservoir contact in a cretaceous tight reservoir to improve production and maximize recovery. Multilateral well campaigns were performed to meet these objectives.
This case study describes an effective workflow for performing openhole sidetracks in this challenging medium-hard carbonate formation. The workflow maintained reservoir contact and achieved the desired production objectives.
Two 6-in. multilateral drain sections were successfully drilled by performing openhole sidetrack using the continuous proportional steering method (CPSM). This method is not new to the industry, but this case study describes the systematic, unique workflow that was designed and followed to ensure a successful sidetrack in this low-porosity, hard formation.
The sidetrack implementation started by creating humps at inclinations ranging from 88 to 91 degrees into the formation in the original 6-in. section. These humps were confirmed using near-bit inclination data (4.5 ft from the bit) and were identified as the sites for initiating a sidetrack. This paper discusses the best practices that were key to the successful execution of the project in one run on the first attempt.
After the sidetrack, use of appropriate combinations of shallow and deep logging-while-drilling (LWD) measurements in the same bottom hole assembly (BHA) enabled the direct geosteering of the well, exposing more reservoir surface area than planned.
A reduction of 10% from the planned well duration was achieved. Two 6-in. laterals, each approximately 4000 ft, were drilled in a single run and 100% reservoir contact was achieved.
This experience proved that planning and precise execution could enable drilling of openhole sidetracks, even through hard formations. These sidetracks can then achieve fishbone wells with desired reservoir contact and realize the field development objectives in a technically robust and cost-efficient manner.
CPSM does not rely on a pressure drop for steering. Although this proof of concept was performed in a relatively hard formation, similar workflows with appropriate drilling engineering may be applied to less-competent formations as well. The detailed procedure and flowchart created from the experience with the sample well can be adopted for use in similar applications.
PCP PDO Wells Runlife Enhancement Using Well Manager
Authors: Al Mamari H. A. 
Published: March 2019

Abstract
OBJECTIVES/SCOPE: Please list the objectives and scope of the proposed paper. (25-75 words) PCP population in PDO fields is around 18% of the total Artificial Lift systems with an average runlife of around 360 days. The main cause of failure are tubing leak and sand resulting in parted rods & pump stuck. Continuous PCP surveillance/ monitoring are key to understand pump performance and hence increase their runlife. With this objective, PDO has installed a PCP Controller application / surveillance tool called Well Manager in number of wells on trial basis. METHODS PROCEDURES, PROCESS: Briefly explain your overall approach, including your methods, procedures and process. (75-100 words) In the current set up, PCPs are operated using speed mode and the fluid level checked occasionally using simple fluid shot apparatus whereas with Well Manager they can be operated using different function like production optimization mode, dynamic fluid level or speed control mode all of these modes can be associated with de-sanding function or torque limiting function. These modes to be functional require running downhole gauge, casing pressure, flow line pressure and surface flow rate meters. Surveillance data collected from these meters while these modes are activated has allowed PCPs to automatically optimize their operating conditions to prevent trip due to sand accumulation and pump stuck and therefore increase runlife time. RESULTS, OBSERVATIONS, CONCLUSIONS: Please describe the results, observations and conclusions of the proposed paper. (100-200 words) New PCP setup was installed in well No.1 aiming to reduce solids whilst keeping production rate as it was expected. Well Manager with automated flushing feature every 8 hours, and down hole gauge installed with ant-vibration sub has led for doubling the run life and eliminating FBU interventions. This has resulted in increasing run life from 113 to 239 days and still running. Moreover, compared to the old design in this well, the new set up managed to produce same flow rate using a smaller pump size with lower solids production rate. Another four units installed and showing positive results as well as stability with less well trips and increase in run life. Please explain how this paper will present novel (new) or additive information to the existing body of literature that can be of benefit to a practicing engineer. (25-75 words) The novelty and combination of the Well Manager set up can be replicated and implemented in all PCP wells in the oil industry helping to increase pumps runlife, reduce well intervention cost and oil deferment and therefore, reducing the life cycle cost.
Development of a Geomechanical Ranking System to Investigate Hydraulic Fracturing Feasibility of an Unconventional Shale Oil/Gas Reservoir: Case Study from Middle East
Authors: Ghadimipour Amir , Singh Hemant , Perumalla Satya 
Published: March 2019

Abstract
As part of a multi-disciplinary study to explore the unconventional shale oil/ gas potential within a prospective carbonate/shale formation in Middle East, geomechanical analysis was carried out to understand the formation characteristics in order to evaluate hydraulic stimulation feasibility. The main objective of the geomechanical analysis was to select the most suitable area for fracturing in the few fields under study. To understand the geomechanical setting across different fields, well based 1-D geomechanical models were built for dozens of wells from few adjacent fields. Rock mechanical tests specifically designed for unconventional reservoirs were performed in cores of selected wells and the results were incorporated in the calibration of geomechanical models.
In general, a mild and very strong strike-slip stress regime was identified over target lime shale and bounding limestone formations, respectively, with very high horizontal stress magnitude and anisotropy noticed in low clay and low TOC layers. Different stimulation scenarios were investigated by using hydraulic fracturing simulation software. The results suggest that the high horizontal stress contrast between target shale and the bounding organic-free limestone formations provide a very strong stress barrier which reduces the risk of out of zone propagation of hydraulic fractures and therefore, increases the efficiency of fracturing job. However, depletion reported within certain layers of interbedded limestone formations in some of these fields in this study, reduces the stress contrast and fracture containment in those fields due to poro-elastic effects.
A geomechanical ranking system was developed to evaluate the relative feasibility and effectiveness of hydraulic fracturing treatments in the prospective shale target and also to identify sweet spots across four fields in the study. In order to develop this ranking system, several properties have been defined and estimated, based on the derived rock mechanical properties and stress models. These parameters address the containment of the fracture within the target shale, complexity of generated fracture and also amount of estimated over-pressure in the target interval. A final geomechanical rank was calculated by assigning a weight multiplier for each ranking parameter based on its relative influence on feasibility and quality of stimulated hydraulic fracture.
Geomechanical ranking (resource accessibility) along with petrophysical ranking (resource volume) have been considered together to produce an integrated "chance of success" statement for different areas within the subject fields. Composite risk maps were developed based on rankings of wells from the study fields. These maps provide information on sweet spots which in turn have been used to shortlist highest ranked areas for the subsequent unconventional development program.