bluuebunny/crossref_metadata_2025 huggingface dataset:
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

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

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

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

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

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

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

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.
Development of a Completion Model for the Monitoring of EOR in Wells with Heavy and Extra Heavy Crude in the Largest Deposit in Latin America
Authors: Pena Gerardo , Patiño Deivy
Published: March 2019

To validate the completion model, a computer simulation was performed in four scenarios to predict mechanical failure limits. Consequently, a completion design model was obtained using vacuum-insolated tubing (VIT) that enables a minimum of 75% of steam quality given an inlet steam quality of 80%. In addition, a seal bore is used at 50° to 60° of inclination, which enables the upper completion disconnection/connection through the seal stinger at that depth, without losing production capabilities for changes in the depth of top of connection of tie-back. This paper describes the type of completion development and challenges encountered during the design. The advantages and benefits of collecting the correct information in the process of thermal recovery in the joint venture are also discussed.

The investigation resulted in a completion model of thermal wells that will enable the monitoring of the conditions of the injection, tubing, casing, and injection effectiveness in the system in which the cyclic process is applied and adjusted to wells in the Orinoco Belt. A conclusion of this investigation is that, during the injection, the movement of production string and the monitoring component must be independent to avoid the transference of stress resulting from thermal expansion. Polished bore receptacles and seal assemblies should be used in the replacement of expansion joints; this will enable the upper completion to be used for recovery and changed for the injection system.

Although completion models have been developed in which the steam path can be monitored, they have not been developed previously for use in long horizontal section wells, as was performed in this case. The problem of thermal expansion of the tubing during steam injection is expected to be resolved with the implementation of the design based on this study. Feed-through packers have already been developed especially for this process, although with a mixed record of successful and unsuccessful deployments. The monitoring system must be mechanically independent of the injection system, such that movements associated with expansion and contraction do not have a significant effect.
Verification of a CFD-Population Balance Model for Crude Oil Separation Efficiency in a Three-Phase Separator – Effect of Emulsion Rheology and Droplet Size Distribution
Authors: Oshinowo Lanre , Vilagines Regis
Published: March 2019

In this study, a multidimensional computational fluid dynamics (CFD), combined with the Population Balance Model, is used to predict the gas, oil, and water separation behavior in a horizontal three-phase high-pressure, high-temperature pilot separator at different flow rates and water cuts, and predict the thickness of the dense packed emulsion layer above the water interface. The multi-fluid Eulerian multiphase model, coupled with a multivariate population balance model, is applied to predict emulsion destabilization and separation, and validated with experimental data. The population balance model is applied to predict the changing droplet size distribution in the crude oil emulsion due to droplet coalescence. The effect of water cut on the emulsion rheology was incorporated in the CFD model to predict the existence of the dense packed layer or zone (DPZ) – a high water-cut emulsion layer formed at the interface between the oil and water phases. A novel emulsion viscosity model incorporates a dependence on the local droplet size. The CFD modeling predicts the flow patterns and phase distributions throughout the separator, and the dispersed water droplet size distribution in the emulsion/liquid phase. Parameter estimation for the droplet coalescence kernel in the population balance equation is determined from experimental measurements of emulsion separation kinetics. A Proportional Integral Derivative (PID) controller logic is used to maintain the gas/oil and oil/water interface levels by automatically adjusting the oil and water outlet pressure, respectively. Experimental data from a high-pressure pilot scale separator is compared to the predicted phase flow rates into and out of the vessel, and vertical phase profiles to CFD results. The CFD model reproduced separation efficiency, three-phase distribution and the DPZ influence on oil-water separation efficiency and demonstrates an effective methodology to evaluating full-scale separator performance.
Advances in Rock Petrography: Image Processing Techniques for Automated Textural Thin Section Analysis
Authors: Mokhles Mezghani , Fatai Anifowose , Mohammed Masrahy
Published: March 2019

Point counting is time consuming and requires extensive geologist/petrographer effort. In addition, point counting results are subjective and depend on the petrographer's knowledge and expertise. In this work, we introduce a fully automated workflow for thin section textural analysis in clastic rocks, using high resolution petrographic images of the thin sections acquired with a digital camera mounted on an optical microscope. This innovative workflow reduces the thin section textural analysis turnaround time and provides an objective and consistent analysis.

The strength of this workflow resides in its high level of automation, which offers thin section analysis tool in much less time compared to the conventional point counting. The workflow is fully automated to process and analyze the entire thin section without manual involvement. The kernel of this workflow is based on a region growing algorithm for individual grain identification. An iterative loop, built on the top of this kernel, allows the completely automated scan of the entire thin section.

The workflow was first rigorously validated for a single thin section. Grain by grain, results from the automated analysis are compared to the petrographer (point counting) analysis. Excellent agreement between the two analyses was obtained (porosity and grain size). The efficiency of the analysis was largely in the favor of the automated approach (3 minutes) compared to the 2 hours needed by the petrographer for this counting exercise (approximately 150 grains). This first validation test proved the workflow's accuracy and the efficiency.

This workflow was then extensively validated using large set of thin sections (50 thin sections) showing an excellent qualitative agreement with conventional point counting. This second validation test proved the robustness and the efficiency of the workflow.
Isotopic Characterization of Formation Waters: Applications and Challenges
Authors: Lu Feng , Harthi Owaidh , Dubaissi Jaffar
Published: March 2019

Formation waters contain important information including the source, reservoir connectivity, and geological/biogeochemical processes, which can be used to aid work associated with petroleum exploration and production. Such information can be obtained by conducting geochemical analyses of water. Isotope technology is one of powerful geochemical tools and has been well applied to characterize formation waters. There are challenges to apply isotope technology. For example, petroleum formation waters commonly contain high total dissolved solids (TDS) and petroleum compounds, which can have a huge impact on the quality of stable H- and O-isotope analyses. Here we present an innovative methodology dealing with high quality of isotope analysis of formation waters, which contain abundant petroleum compounds and high TDS. The most widely used method of analyzing oxygen isotopes in water involves pure CO2 gas interaction with the targeted water for twenty-four hours, and then measure O- isotopes of CO2. However, some studies have indicated that the exchange rate of oxygen isotopes between CO2 and water highly depends on the amount of TDS in water. Experimental work in this study indicates that the established period of time (24 hours) is too short to reach isotope equilibrium between CO2 gas and typical petroleum formation waters, which commonly have a high TDS. This study shows that waters with different ranges of TDS require different periods of time for water-CO2 interaction to reach an isotope equilibrium. In addition, experimental work has shown that petroleum compounds dissolved in formation water have gravely affected the quality of both O- and H-isotope analyses. Experimental work of removing petroleum compounds was conducted, and the effective processes have made it possible to successfully achieve the high quality of isotope analysis.
Artificial Neural Network ANN Approach to Predict Fracture Pressure
Authors: Ahmed S Abdulmalek , Elkatatny Salaheldin , Ali Abdulwahab Z , Abdulraheem Abdulazeez , Mahmoud Mohamed
Published: March 2019

Fracture pressure is a critical formation condition that affects efficiency and economy of drilling operations. The knowledge of the fracture pressure is significant to control the well. It will assist in avoiding problems associated with drilling operation and decreasing the cost of drilling operation. It is essential to predict fracture pressure accurately prior to drilling process to prevent various issues for example fluid loss, kicks, fracture the formation, differential pipe sticking, heaving shale and blowouts.

Many models are used to estimate the fracture pressure either from log information or formation strengths. However, these models have some limitations such as some of the models can only be used in clean shales, applicable only for the pressure generated by under-compaction mechanism and some of them are not applicable in unloading formations. Few papers used artificial intelligence (AI) to estimate the fracture pressure. In this work, a real filed data that contain only the real time surface drilling parameters were utilized by artificial neural network (ANN) to predict the fracture pressure.

The results indicated that artificial neural network (ANN) predicted the fracture pressures with an excellent precision where the coefficient of determination (R2) is greater than 0.99. In addition, the artificial neural network (ANN) was compared with other fracture pressure models such as Matthews and Kelly model, which is one of the most used models in the prediction of the fracture pressure in the field. Artificial neural network (ANN) model outperformed the fracture models by a high margin and by its simple prediction of fracture pressure where it can predict the fracture pressure from only the real time surface drilling parameters, which are easily available.
Using Data Driven Analytical Models with Compositional Simulation in Doubling the LPG Production from Bahrain Field
Authors: AlMuftah Ali , AlOwainati Ebrahim , Mansoor Mohamed
Published: March 2019

Crestal gas injection started in the Bahrain Field in 1938 and since then, 1,900 Bscf has been injected in Mauddud, the main oil producing reservoir in the Bahrain Field, creating a secondary gas cap. Furthermore, since 1965, an estimated 100 MMstb of Liquefied Petroleum Gas (LPG), or 14% of the bypassed oil, has been recovered from the secondary gas cap through stripping with the remaining oil volume in the secondary gas cap being approximately 700 MMstb. Today, the remaining oil saturation in the Mauddud gas cap is estimated to be approximately 40%.

This paper presents the results of an extensive study that was made to forecast the Bahrain Field associated gas compositions and potential gas-liquids production recovery. Several forecast methodologies were used including data-driven analytical models, a compositional cross-section model, and a full-field compositional history matched model. The results of these forecasts and the conclusions are presented and compared. In this study, two scenarios of different gas compositions of injected gas and their impact on gas plant liquids recovery are explored.

In addition, this paper addresses the challenges and uncertainties associated in forecasting the gas compositions and ways to overcome them. The data-driven models and compositional cross-section model were initially used, however, due to their inherent uncertainties, a full field compositional simulation model was necessary. This compositional model was history matched with a seven (7) component Equation of State (EOS) to capture the lighter hydrocarbon components. Moreover, this model was used in predicting the yield and composition of the existing gas recovery plant. The results from all methods recommend doubling the capacity of the existing plant, which was commissioned in late 2018. A comparative analysis found that data-driven models can be used for gas cycling when using the same gas injection compositions. However, data-driven models over-estimate the Liquefied Petroleum Gas (LPG) yield if leaner gas is used for gas injection, which is the case for the proposed gas plant expansion.
First Worldwide Application of HP/HT Water Swellable Packers Eliminates Deployment Risks and Improves MSF Efficiency in Tight Gas Reservoirs
Authors: Arias Rommel E. , Guizada Pablo , Mohanna Khalid Al , Desai Ankur
Published: March 2019

This paper presents the first-time application of high pressure/high temperature (HP/HT) water swellable packers worldwide for multistage fracturing completions. This technology eliminates deployment risks associated with premature swelling in high temperature oil-based muds (OBM) and improves efficiency of fracturing operations in tight gas reservoirs.

The overall deployment method of this technology is similar to traditional open-hole multistage fracturing technologies that are industry standard. The main difference being that the isolation packer used is an HP/HT water swell packer that uses water/brine as the swelling medium as opposed to hydrocarbon. The technology comprises of an innovative compound that is capable of holding high differential pressure at high reservoir temperatures and maintaining permanent isolation in a relatively compact element length. The elastomer compound completed an extended qualification process to ensure fulfilling deployment and fracturing completion requirements in a specific well candidate.

The outcome was an overall successful deployment and stimulation operation of multi stage completion with HPHT water swell packer technology. Water swell packer provided the ability to deploy the lower completion in high temperature/OBM environment with a significant increase of swelling factor delay and its compact length reduces stiffness in the BHA to further decrease the deployment risk. In addition, this technology provided an optimization technique for open-hole multi-stage stimulation by circulating out the drilling mud and leaving completion brine in the wellbore and annular space. Through a complete diagnostic process, it was confirmed that the water swellable packers successfully isolated each stage of the stimulation treatment.

Prior to the first worldwide installation of an innovative elastomer compound, unique testing was conducted in the laboratory and in field tests to qualify the compound technology with special focus on the acid stimulation treatments domain. The elastomer compound was made of special fillers to chemically retain water in the elastomer matrix and eliminate any reverse osmosis problem present in traditional water-swellable compounds.
Deployment and Detection of a Novel Barcoded Advanced Tracers System for the Optimization of Improved Waterflood Recovery in Hydrocarbon Reservoirs
Authors: Thomas Gawain , Ow Hooisweng , Chang Sehoon , Shi Rena , Wang Wei , Chen Hsieh , Poitzsch Martin , Shateeb Hussain , Abdel-Fattah Amr
Published: March 2019

Objectives/Scope

A novel barcoded advanced tracers system has been developed and field-validated in a hydrocarbon reservoir. With a detection scheme that supports automation, this cost-effective tracers system is designed to enable potentially ubiquitous long-term full-field injections in the interest of using the high fidelity tracer data to increase the oil recovery factor through improved optimization of the water injection and oil production.

Methods, Procedures, Process

Our Advanced Tracers system uses real-time chromatographic separation and optical detection to achieve ultra-low limits of detection (LOD) at 1 part per billion (ppb) or better. Such low LOD facilitates small injection quantities, making full field deployment of Advanced Tracers cost-effective compared to state-of-the-art interwell tracers. Additionally, the detection strategy that enables automation of the analysis process for real-time tracer detection is outlined, paving way for minimal manual sample collection and work-up.

Results, Observations, Conclusions

Results on recently field-validated real-time optically-detectable tracers in a hydrocarbon reservoir, detectable at ultra-low LODs, are described. This is achieved even in the presence of background oil by means of an intrinsically oil-blind detection method. The material exhibits high mobility in high-salinity high-temperature carbonate reservoirs, with tracer breakthrough successfully detected at concentrations of less than 1 ppb using chromatographic separation followed by an optical detection method. The novel methodology as outlined highlights its simplicity, safety and cost-effectiveness relative to current practices in the field.

Novel/Additive Information

Fluorobenzoic acid based tracer technology requires chemical derivatization of the samples for ultra-low detection limits in a GC-MS. Our novel tracer detection strategy omits the need for chemical derivatization. In addition, it enables a compact, portable, optical-based automated wellsite detection system to be used in the field, with tens of unique barcodes possible. These innovative steps are keys to near real-time tracer detection in the field, realizing one of the intelligent oil field monitoring and the reservoir management applications.
The Development of a Novel Log Based Permeability Transform for a Mature Carbonate Reservoir and its Significance in Explaining the Water Flood EOR Response
Authors: Dowen Michael , AlAli Abdulkarim , Nemmawi Nadia
Published: March 2019

The unexpected response of the Mauddud water flood project led to a detailed review of the petrophysical and geological aspects of this mature cretaceous carbonate reservoir. With almost 2,000 wells, more than 1,000 of which were recently drilled and three cored, the review assessed an extensive data base of open-hole, production, saturation log, and historical geological data.

The findings resulted in an improved understanding of this reservoir, which historically had been described both as homogenous - fractured and heterogeneous – layered. An understanding of Mauddud's key geological features, their formation, and a link to the observed petrophysics provided the key to developing an innovative permeability transform from resistivity logs, which explained the reservoirs response to the water flood project.

With production permeability up to fifty times the measured matrix permeability from core, porosity log derived permeability had failed to reflect the fluid production observed. The adoption of a saturation and production based method provided a useable permeability profile that appeared to explain the observed well and pattern production behavior of the water flood. The new permeability profile also explained both historical fluid behavior and other Enhanced Oil Recovery (EOR) projects, and has since been universally adopted for the reservoir.

The permeability estimation technique, which uses resistivity log data, was tested in another in-field reservoir with success, and it is thought that the technique has general applicability across many Middle East carbonate reservoirs.
Improving Efficiency and Accuracy in Estimating Well Potential Using an Integrated Asset Operations Model
Authors: Cornwall Rachelle Christine , Mubarak Al Nuimi Saber , Tripathi Deepak , Hidalgo Melvin , Soni Sandeep
Published: March 2019

This paper describes an efficient approach for estimating well potential using advanced, automated workflows for a large field with more than a thousand well strings from multi-layered reservoirs having different characteristics. This paper provides insight into reservoir guidelines, well performance, and surface facility constraints using the integrated asset operations model (IAOM) to compute well potential.

The IAOM tool automates an engineering approach in which reservoir management guidelines, in conjunction with calibrated wells and a network model, are used to estimate well potentials. This process incorporates the interaction among various components including wellbore dynamics (Inflow performance and well performance), surface network backpressure effects and well performance key parameters, such as GOR and water cut. This engineered workflow computes the well potential corresponding to each guideline and constraint.

This engineered workflow has reduced the time to compute the well potential rate from 3-4 weeks to just 2 hours for this large field, reducing computation time by more than 95%. This workflow helped engineers to avoid tedious manual calculations on a well-by-well basis and allowed them to focus on engineering, analytical, and optimization problems. The confirmation of calculated well potential rates using the updated surface network model helped in finalizing the business scenarios such as field-capacity tests. For example, the accuracy of predicted results in a zonal capacity test was approximately 98% using this engineered workflow approach. The value derived from this engineering logic using validated physical models supported the business plan and further identified key candidates for production optimization without heavy dependence on drilling additional wells, leading to cost optimization. This automated workflow ensures the use of updated physical models and maintains higher accuracy of results. This digital system-based data-management process supports data governance objectives.

This enhanced workflow supports corporate objectives of standardization for a work process to set well allowable, in line with the operator's integrated reservoir management (IRM) initiative.
Geological Modelling of the Enjefa Beach Marginal Marine Outcrop; A Comparison Between Holocene and Cretaceous Tidal Channel Complexes
Authors: Amer Aimen , Al-Wadi Meshal , Salem Hanan , Sajer Abdulazziz , Al-Hajeri Mubarak , Najem Ali
Published: March 2019

Outcrop work represents the main source of analogs used to model subsurface reservoirs. Without such explanation of reservoir geometry, architecture, and characterization, producing subsurface formations would be largely uncertain. The aim of this paper is to build a geological static model for the Enjefa Beach outcrop exposed in Kuwait and use it to better understand subsurface reservoir architectures. This was achieved by acquiring several traverses along the outcrop, describing the various rock units, and understanding the depositional facies and facies associations. The next stage was to model each depositional unit as a separate zone embedded in an integrated model. This was followed by developing a forward synthetic three-dimensional seismic model to better understand how such reservoir architecture may appear in the subsurface. The final step was to use these findings in modeling a subsurface Cretaceous reservoir in northeastern Kuwait. The resultant model demonstrated that detailed geological complexities can be captured by conventional modeling techniques; in the model, the middle shoreface, upper shoreface, foreshore, and tidal channel complexes were statically modeled. Subsurface seismic data showed a series of highly sinuous meandering channels. Stacking patterns were found to vary among vertical, climbing, and compensational stacking patterns.
Quantitative Digital Petrography: Full Thin Section Quantification of Pore Space and Grains
Authors: Buono Antonio , Fullmer Shawn , Luck Kelly , Peterson Keith , king Hubert , More PJ , LeBlanc Stephanie
Published: March 2019

Carbonate reservoirs are often comprised of a heterogeneous pore system within a matrix of variably distributed minerals including anhydrite, dolomite, and calcite. When describing carbonate thin sections, it is routine to assign relative abundance levels to each of these components, which are qualitative to semi-quantitative (e.g. point-counting) and vary greatly depending on the petrographer. Over the past few decades, image analysis has gained wide use among petrographers, however, thin section characterization using this technique has been primarily limited to the pore space due to the difficulty associated with optical recognition beyond the blue-dyed epoxy associated with the pores. Here, we present a new method of computerized object-based image segmentation (Quantitative Digital Petrography: QDP) that relies on a predefined rule set to enable rapid, automated thin section quantification with only minor human interaction. We have developed a novel work flow that automatically isolates the sample on a high-resolution (i.e. <1μm/pixel) scanned thin section, segments the image, and assigns those segments to predefined categories – e.g., pores, cement, grains, etc. Using this technique, statistically relevant numbers of thin sections can be rapidly processed and quality controlled, thereby allowing quantitative data such as MICP, wettability, and surveillance data to be integrated with the petrographic observations for a more complete description of the carbonate rock. Our technique can also incorporate multiple layers, such as cross-polarization, Back Scatter Electron (BSE) imaging, and elemental maps, which allow additional information to be easily integrated with results from QDP. The QDP approach is a significant improvement over previous digital image analysis methods because it 1) does not require binarization, 2) eliminates the subjectivity in assessing abundance levels, 3) requires less hands-on time for the petrographer, and 4) provides a much fuller dataset that can be incorporated across an entire well or field to better address common challenges associated with carbonate reservoir characterization, such as understanding pore type and cement abundance, pore connectivity, grain distribution, and reservoir flow characteristics.
Comparative Analysis of Full-Cycle Cost of Oil and Gas Exploration, Development and Production World-Wide
Authors: Virine Lev , McCoskey Steven
Published: March 2019

Understanding the full-cycle cost of oil and gas exploration, development, and production is critical for petroleum producers and all players in the oil and gas industry. In particular, full-cycle cost assessment is used for corporate planning, acquisitions, operational improvements, project control, and risk management. The challenge is to ensure that full-cycle cost assessment is done accurately and on a consistent basis across different jurisdictions, companies, and geographic areas. Without knowing the full-cycle cost on a consistent basis worldwide, it is impossible to assess capital investment, forecast production from different areas, forecast prices, or assess other factors influencing the world market for oil and gas. This paper discusses the methodology for and the results of full-cycle cost assessment worldwide.

This paper describes a methodology for full-cycle cost assessment that ensures data quality and consistency. It also provides examples of full-cycle cost assessment for major projects worldwide. The results of analysis help to predict long-term pricing trends, determine areas where production will grow or decline, and estimate capital expenditure in the next 10–20 years based on the most recent and most consistent data.
Challenges with Mega-Projects Implementation: Risk Strategies and Opportunities for Growth
Authors: Akimova Irina
Published: March 2019

Russia always plays an important role on iternational energy markets as one of the major oil and gas producers and exporters since the country entered international enrgy market in the middle of the last century. And this role will remain stable at least till the year 2040 according to current forecasts. BP estimates, that Russia will cover around 5% of the global energy demand by the year 2040. Though, Russia has around 17,4% of world gas reserves (OPEC's estimates its even more – around 24,6% due to the different methodology) and only around 6% in world oil reserves, Russia contributes 17,3% to world gas production and 12,2% to world oil production in 2018, according to BP's Statistical Review of World Energy. Developing of enormous gas and oil reserves was extraordinary challenging for the country due to harsh climate conditions, lack of infrastructure, unsufficient financing and need to develop not only fields but the whole remote areas of the country. Though the country was widely ctitised for its dominancy on the European gas market, in this paper it will be outline that developing of the European gas market was of mutual interest of Russia and European Union and both counterpart became beneficiary of it. This paper focuses on challengies with developing enormous gas reserves as Russia has several mega giant gas fields and its experience can be usefull in developing other mega projects around the world.