bluuebunny/crossref_metadata_2025 huggingface dataset:
Modelling the Coupled Effects of Temperature, Injection Rate and Microbial Kinetic Parameters on Oil Recovery by Microbial Flooding
Authors: Sivasankar P. , Govindarajan Suresh Kumar
Published: July 2016

Before the implementation of microbial enhanced oil recovery (MEOR) technique in reservoirs, the microbes used in the MEOR process must be characterized based on the reservoir conditions that include reservoir temperature and also based on the microbe's kinetic parameters that includes yield of microbes with respect to nutrient (YXN) and yield of biosurfactants with respect to nutrients (YPN) for efficient recovery of crude oil from hydrocarbon reservoirs. In addition to chrecterization of microbes based on the reservoir temperature and on its kinetic parameters, the operational condition such as injection rate has also to be selected suitably for better oil recovery and to make the microbial enhanced oil recovery (MEOR) process an efficient technique. Hence in the present study, sensitivity analysis of reservoir temperature, injection rate and microbial kinetic parametrs on MEOR processes has been carried out to characterize the microbes and to identify the suitable injection rate for the MEOR process. For this purpose, a black oil microbial enhanced oil recovery (MEOR) simulator has been developed by coupling of thermo-hydro-biochemical multispecies reactive transport model with the non-isothermal multiphase fluid flow model that can predict the oil recovery at varied reservoir temperature conditions. The developed mathematical model has been solved numerically by finite volume discretization technique. The identification of suitable conditions of microbe, nutrient and injection rate to maximize the oil recovery has been carried out by investigating the sensitivity of reservoir temperature, injection flow rate and yield of microbes with respect to nutrient (YXN), yield of biosurfactants with respect to nutrients (YPN) on MEOR processes. It is found that the microbes used for MEOR application should have its survivable temperature range within the reservoir temperature for an effective MEOR application. Further, it is observed that for maximizing the oil recovery by microbial flooding process, the adopted injection rate should increases the capillary number to 10-3 within the reservoir which has to be achieved by increasing the mean aqueous phase fluid velocity and also by lowering the Interfacial tension. Finally, it is also found that more of the residual oil is recovered when the utilization of nutrients for biosurfacatnt production is greater or equal to the nutrients utilized for the microbial growth. Hence for an efficient MEOR application, the nutrient selected for the application should yield more biosurfactants than yielding the microbes that are selected for the MEOR application.
A Cost-Effective Method to Maximize the Hydrocarbon Recovery by Optimizing the Vertical Well Placements through the Simulation Opportunity Index
Authors: Saputra Wardana , Ariadji Tutuka , Patzek Tadeusz W.
Published: July 2016

During periods of low oil prices, profitability of field developments drops drastically. To help with this difficulty, we offer a cost-effective method of boosting hydrocarbon recovery by optimizing well locations.

A new software program has been developed to optimize vertical well placements based on the Simulated Opportunity Index (SOI). SOI is an intelligent method to identify zones with high potential for production. The production potential of an oil & gas field area is empirically calculated from basic rock and fluid properties, and from reservoir pressure as its energy capacity. In order to obtain the best results, the original SOI formula (Molina et al., 2009) was extended to both oil and gas fields.

With the new SOI software, it is possible to rank the best layers in each areal location, resulting in appropriate vertical well locations and perforated intervals in multilayer reservoirs. Furthermore, the developed software can account for the effects of existing wells and sealing faults to accommodate infill programs in brown fields and compartmentalized reservoirs.

This paper describes how the software helps in obtaining optimal solutions with better accuracy than previous studies resulting in the highest recovery for three different case studies in an oil and gas field located in offshore Indonesia. The sensitivity analysis that was performed shows a strong relationship between SOI value and recovery factor. It validates that the higher SOI values selected by the software give higher recovery factors.

The developed software could boost field development projects even in the period of low oil prices. On one hand, the proposed method could save money by minimizing the required number of wells. On the other hand, it could maximize profit by maximizing recovery.
Oil Well Flow Rates and Components Fraction Prediction Using Nonparametric Variable Similarity Based Modeling
Authors: Abado S. , Hu X. , Shah V.
Published: July 2016

The Variable Similarity Based Modeling and Virtual Signal Generation algorithms are applied to continuously predict (infer) the values of flow rates and component fractions in between periodic oil well tests. This method uses the time-varying signals collected during irregular well tests to train a nonparametric regression model which represents the current operating state of the well. Additionally, this approach also provides the benefit of early warning on potential well performance degradation or other anomalies. The proposed approach was shown of being able to predict the oil, gas and water flow with relatively small errors (~3%, ~3% and ~10%, respectively).
New Non-Explosive Setting Tool
Authors: Al-Julaih Bassam , Christie Stewart , Duncan Neil , Church Paul
Published: July 2016

Historically bridge plugs, packers and gauge hangers were set with explosive charge or hydrostatic setting tools. The logistical and safety issues associated with explosive type setting tools has resulted in more operators moving towards non-explosive setting tools over the last two decades. Hydrostatic setting tools have limited setting force capability related to well conditions.

This paper discusses the design and benefits of a new electro-mechanical setting tool, the New Setting Tool, which aims to significantly reduce operating costs while greatly improving ease of use and reliability.

The New Setting Tool addresses many of the issues associated with commonly used setting tools. The New Setting Tool does not require highly trained personnel or explosives. The tool does not require re-dress after each run and does not require lithium battery packs. Lithium battery packs are commonly used in electro-mechanical setting tools and are classed as dangerous goods. Regulations regarding the shipment of lithium batteries have become more stringent in recent years increasing the time and costs associated with shipment and disposal.

In memory mode, the New Setting Tool utilizes a simple, patent-pending touch screen interface called Cyclops Touch, on the tool body. Touch screen technology is common place in everyday life. A major technical challenge in the design and development of New Setting Tool was to introduce this technology into a downhole tool that is subject to the extremes of temperature and pressure associated with an oil or gas well.

This technically advanced user interface has reduced the requirement for extensive user training. The operator can program the tool and interrogate diagnostic information without the need to disassemble the tool at surface or break any field connections. This is a significant benefit when working in hazardous areas.

The New Setting Tool has an integral auto-reset feature which re-sets the tool for redeployment in less than a minute.

The setting tool comprises of three main sections, the power section, Cyclops section and the hydraulic section. Each section has been designed with specific parameters to ensure the tool is highly reliable and easy to program and run. The non elastomeric seal design allows the tool to be run up to 50 times without re-dress. This improves efficiency and reduces personnel requirement on location.
Estimating the Degree of Inter-Reservoir Communication Between Two Reservoirs Using Advanced Numerical Well Testing Model
Authors: Al-Wehaibi B. A. , Anisur Rahman N. M. , Issaka M. B.
Published: July 2016

The inter-reservoir communication plays a major role in the dynamic performance of any reservoir. Hence, characterizing and understanding the degree of the communication is essential in modeling the reservoir behavior. This paper demonstrates the power of the pressure transient tests in successfully detecting and characterizing the communication between two reservoirs separated by a very thin tight layer as a case study. It also presents the results of integrated pressure transient analyses for long build-up tests conducted in one of the wells, the data of which was acquired from the PDHMS. These confirm the inter-reservoir communication in this field. Using a numerical interpretation technique, a rigorous multi-layer model has successfully matched the pressure transient data and has helped estimating the degree of the communication between the two reservoirs. It has also allowed characterizing the thin tight layer that separates the two reservoirs and controls the inter-reservoir hydraulic communication. This work will help the simulation models of the field to quantify the degree of the communication and capture the real performance of the reservoirs in order to achieve better and effective reservoir management and development plans.
Single-Well Chemical Tracer Test for Residual Oil Measurement: Field Trial and Case Study
Authors: AlAbbad Mohammed , Balasubramanian Senthilmurugan , Sanni Modiu , Kokal Sunil , Zefzafy Ibrahim , Adam Frederick , AlHajji Adnan
Published: July 2016

Tracers are increasingly being deployed as an effective reservoir monitoring and surveillance (M&S) tool in the oil and gas industry. In particular, the single-well chemical tracer test (SWCTT) is being widely used to estimate remaining oil saturation (ROS) or residual oil saturation (Sor), especially in improved oil recovery (IOR) and enhanced oil recovery (EOR) operations. The test provides a direct measure of ROS in a wider reservoir volume compared to the measurements made by near wellbore logs or cores.

A SWCTT was designed and implemented in a carbonate field to determine fluid saturations. The reservoir is heterogeneous with layers of high to low permeability limestone, porosity in the range of 20–30%, and interspersed with patchy layers of dolomites and a very competent anhydrite seal. The SWCTT was conducted in a very mature part of the field near the peripheral water injectors, to determine the residual oil saturation before a planned IOR pilot test.

This paper presents the complete design and implementation of the test, operational challenges, and the analyses and interpretation of the results. The depth of investigation was 13–14 feet from the wellbore. Laboratory results of determining the partitioning coefficient of the chemical tracer are described and presented. The design of the tracer test taking into consideration the reservoir properties are shared. Considerable operational challenges in the field and appropriate solutions to overcome them provide a very interesting case study. The returns and analyses of the samples provided a unique set of data that were interpreted using a simple analytical tracer model which was comparable to the reservoir simulations predictions. The Sor was obtained after fitting the tracer return data to a model of the classical convection-dispersion equation. The results indicate that there was no displacement or drift that occurred during the shut-in period. The mass balance of the tracers suggests that more than 98% of the tracers were recovered with negligible tracer adsorption during the test duration. The results are in close agreement with a similar test benchmarked independently by a commercial vendor using a different injection design scheme.
Geochemical Monitoring Plan for the First CO2-EOR and Sequestration Project in Saudi Arabia
Authors: Balasubramanian Senthilmurugan , Sanni Modiu , Kokal Sunil , Oduro Harry , Yu Haichao , Al-Hajji Adnan , Adam Frederick
Published: July 2016

Saudi Aramco is implementing its first carbon-dioxide enhanced oil recovery (CO2-EOR) carbon capture, utilization and storage (CCUS) demonstration project in a small depleted part of a carbonate reservoir, as part of its environmental stewardship and its efforts to mitigate CO2 emissions. It is worth mentioning that Saudi Aramco does not require EOR oil for many decades to come. This project is being implemented primarily to demonstrate the feasibility of sequestering CO2 through EOR in the Kingdom and using it as grounds to test new monitoring and surveillance (M&S) technologies. The injected CO2 is expected to react with formation fluid (oil and water) and rock minerals for geological storage to occur. Reservoir simulation studies suggest about 40-50% of the injected CO2 will be sequestered permanently in the reservoir.

To understand the geological trapping process and also to identify and quantify any inadvertent "out-of-zone" CO2 leakage, a comprehensive geochemical monitoring (geochem) program has been developed and is being deployed. The objectives of the geochem program are to monitor the project before, during and after CO2 injection to assess the efficacy of the sequestration process. In addition, the geochem data will provide the pertinent information for calibrating the CO2 reactive transport model to be used to quantify and predict the amount of CO2 that will be sequestered over a long period. The geochem plan includes monitoring the changes in basic ionic compositions of reservoir and aquifer water, pH, dissolved organic carbons (DOCs), volatile organic carbons (VOCs), BTEX, etc., and changes in isotopes of carbon, oxygen, hydrogen. Furthermore, the plan also includes monitoring the changes in soil gas (CO2, CH4, O2, Ar, Rn, and He) concentration.

Baseline and time-lapse data are being collected. These provide the basic input to our reactive transport model. The results from the analyses of the reservoir fluid indicate very little value may be derived from monitoring time-lapse isotopic changes. Isotope clumping is considered as a better approach to understand and quantify the amount CO2 being sequestered. This paper reviews the design and implementation of the geochem plan for the project, operational issues, the results obtained to date and the use of "clumped-isotope" geochemistry. Plans for further implementation of the geochem program and the lessons learned will be shared. The geochem plan is deemed robust and will help with understanding, tracking, monitoring and predicting the geo-sequestration process.
First Successful Installation of a 4-1/2 Pre-Perforated Liner through a 5-1/2 Solid Expandable Liner
Authors: Al Rubaii Mohammed Murif , Shehri Hasan H. , Nwachukwu Cosmas N. , Andrews Stacey , Atallah Yasser
Published: July 2016

Sustaining field proven technologies in mature fields and maximizing Return of Investment (ROI) is a priority for operators worldwide. Financial constraints such as oil and gas prices, drilling cost, and any intangibles must not burden the success of pushing limits to open new horizons, not just for the present time but also for future generations. Parallel to reaching new limits, we must keep an eye on the safety and engineering behind any step taken toward the limit to push the envelope successfully. Drilling team recently used a a vendor product to maximize production, isolate a loss circulation zone, and push the operating envelop by installing the first 4-1/2" open hole completion (Pre-perforated liner) with inflatable open hole isolation packers through a 5-1/2" × 7" open hole liner (OHL). The vendor product enabled Saudi Aramco to install 5-1/2" × 7" solid expandable liner installation. The 5-½" 18.24 lb/ft solid expandable systems was utilized to isolate a loss zone and reactive shale section, sealing off the problematic interval and allowing an extended lateral section to be drilled through the reservoir. The expandable liner was run through a window cut through 7" 26 lb/ft casing and subsequently installed across part of the curve section to isolate the lost circulation zone. The use of the expandable liner enables the ability to drill the remaining build section and horizontal section together with full circulation. This paper describes the challenge and application.
Sequential Mineralogy Characterization of Organic-Rich Shale: Example from the Hanadir Shale, Northwest Saudi Arabia
Authors: Abouelresh M. , Babalola L. , Al-Ghamdi T. , Al-Abdullatif A. , El Hajj H.
Published: July 2016

The Middle Ordovician (Middle to Late Cardocian) Hanadir Shale member of the Qasim Formation is a potential shale gas exploration target. This paper quantitatively characterizes the mineralogy of the Hanadir Shale using an applied methodology to better understand the interrelationship between mineralogy and reservoir properties of shale gas formations.

A 9-m thick sequence of the Hanadir Shale within the Tabuk quadrangle in northwest Saudi Arabia was investigated using sedimentological, geochemical, and mineralogical analyses. Sequential analyses were performed on shale samples: X-ray diffraction (XRD), X-ray fluorescence (XRF), cations exchange capacity (CEC), and linear swelling meter (LSM). This shale sequence is dominantly comprised of laminated clay-rich shale interbedded with thin siltstone to very fine sandstone beds. It is overlying a 5-m thick bearing with massive-to-low-angle crossbedding in the uppermost intervals of the Sajir member of the Saq Formation and underlying 30-m thick tigillites in the Kahfah member.

The XRD results showed the Hanadir Shale is characterized by similar mineralogical composition of different proportions with all the samples containing high silica content (~50%), K-feldspar (~30%), and Na-feldspar (3%). Compared to the bulk mineralogy of the shale gas, clay content in the samples (10 to 20%) is relatively low. The identified clay types include kaolinite, illite, and smectite. Carbonate minerals (calcite and dolomite) also occur as traces (~1%) in all the samples. Swelling tests were performed to understand the swelling properties of the clay content and better understand reservoir properties, performance, and fluid properties in the Qasim Shale's reservoir equivalents. The study contributes to the existing database of shale gas exploration information.

Clay mineral distribution patterns and their effects on the reservoir quality of the unconventional shale gas are not well understood; therefore, this study contributes to the understanding of the reservoir behavior of not only the Hanadir Shale but also other regional potential shale formations.
Permeability Prediction Based on Leaky-Capillary-Tubes Using Genetic Algorithm
Authors: Nizamuddin S. , Hossain M. Enamul , Abdulazeez A. , Hassan M. R.
Published: July 2016

For any reservoir, the cross-plot of permeability vs. porosity data exhibit a non-linear behavior. As a result, there is always an uncertainty associated with the characteristic parameters obtained for any permeability equation using inverse-linear-regression technique. In this paper, unique characteristic parameters of permeability equation based on Civan's leaky-tube-capillary model were determined using genetic algorithm to obtain straight-line plot of the derived permeability vs. normalized porosity data.

The statistical inverse-linear-regression techniques are more likely to end up in a local minimum without ever finding the global minimum. Consequently, it results in finding non-unique characteristic parameters of the permeability function. However, heuristic-based optimization technique such as genetic algorithm randomly jump out of the local minima and finds the global minimum of the permeability function. This helps in finding unique value of the characteristic parameters specifically cement exclusion factor, power law exponent, inter-connectivity parameter and other constants resulting in a high correlation coefficient of derived permeability vs. normalized porosity cross-plot.

The unique characteristic parameters obtained by global minimization of permeability function can determine a wide range of permeability values with higher accuracy. On the other hand, the non-unique parameters determined from local minimization are suitable for a limited range of porosity-permeability data. The correlation coefficients for the cross-plot of derived permeability vs. normalized porosity using unique characteristic parameters was found to be close to unity for various data sets obtained from literature. The presented method of finding parameters of a permeability function also reduces the experimentation cost and time.

The novelty of the heuristic-based optimization techniques such as genetic algorithm is in its capacity to find the global minimum of the permeability function. This helps in obtaining unique characteristic parameters for a particular set of permeability-porosity data.
An Assisted Method for Depositional Facies Mapping and Reservoir Connectivity Evaluation Based on Converted Pressure
Authors: Li Yong , Li Baozhu , Tian Changbing , Zhu Yixiang , Qian Qihao
Published: July 2016

Formation test pressure is one of the most important and invaluable surveillance data to understand reservoir dynamic behavior, but usually pressure of different wells are not tested at the same time which limit its function. This paper proposed a simplified material balance equation to convert all tested pressure to the same date, then use converted pressure to assist depositional facies mapping and reservoir connectivity evaluation.

Take M1 reservoir for example, all pressure data are converted to the same artificial test date with a simplified material balance equation. The material balance equation is simplified under certain assumptions, which is similar to that of volumetric undersaturated oil reservoirs. Then wells were classified into different groups for each zone according to their converted depletion pressure change behavior, and depositional facies and reservoir lateral connectivity of different groups of wells are analyzed with clear understanding and obvious characteristics.

M1 reservoir is a multi-layered sandstone reservoir under primary depletion currently, which have 18 wells conducted formation test from 2010 to 2011. It is found that pressure analysis of these wells have no obvious characteristic. But after all pressures converted to the same date with well production constrained, depletion pressure change has clear trend. Then for each zone, wells were classified into different groups according to pressure change behavior, which indicates pressure depletion is similar in the same group while much different from that of other groups. Converted pressure data were analyzed in detail for each zone and used for depositional facies mapping and reservoir connectivity evaluation. Most are consistent between pressure depletion behavior and geological understanding, but some also have contradictions which helps to revise depositional facies. For reservoir connectivity, similar results of depositional facies are drawn.

This paper offers a case study of converting pressure to the same date based on simplified material balance equation, and how to use converted pressure for depositional facies mapping and reservoir connectivity evaluation study are also detailed presented.
On Job Training OJT Accelerated Learning of Reservoir Management Engineers
Authors: AL-Muraikhi Ahmad , Shenawi Shamsuddin , Elhayek Soha
Published: July 2016

On Job Training (OJT) for new fresh graduate reservoir engineers has been implemented at Saudi Aramco. The workshop is offered following completion of the company run on-boarding program offered by Upstream Professional Development Center (UPDC). The objective of this new training is to accelerate the young engineers' knowledge and experience and reduce the professional gap existing in the oil industry. This is being achieved by going in detail through one of the mature reservoirs with a long production history. The young engineers are chartered with the main objective of the reservoir engineers which is the SWEEP. They are trained to conduct detailed analyses of wells and reservoir production/injection performance with the primary focus of determining the current sweep efficiency. Participants are tasked to develop solutions to improve the recovery and the sweep areally and vertically to ensure that the maximum percentage of the reserve is produced.

The number of the participants in each workshop is 12 with different level of experience varying from few months to three years. The participants come from different Up-stream organizations; Reservoir Management, Reservoir Simulation, Reservoir Description, Well testing, Facilities and Computer engineers; Geologist and Geophysicists.

The workshop starts with explaining the ROLE OF RESERVOIR MANAGEMENT. It segments the process into three main areas. The first is to understand the static nature of the reservoir mainly the matrix information. The second is the dynamic part which is the fluid movements and its properties. And the third part is the integrations between the two natures which is used to further understand the complexity of the reservoir and the inter connection between the wells.

The participants practice during their training the ability of extracting the data related to the field and analyzing it thoroughly. Then the data is put-together and integrated to explain the fluid dynamic movements. The trainees as well, develop their reservoir thinking skills by identifying the challenges and formulating future action plans to improve the sweep and maximize the oil recovery.

OJT accelerate learning of young engineers from a variety of universities around the world. This training provided a solid foundation for participants as it help them to deal with real-life examples and help them to sharpen their analyzing and thinking abilities to prepare them for the new reservoir engineering era.
Self-Organizing Maps for Regions Exploring and Identification Based on Geological Signatures Similarities and Anomalies
Authors: Dossary Mubarak , Al-Turki Ali , Harbi Badr
Published: July 2016

Modern reservoir simulation models include very detailed description of geology to enable accurate physics solutions. In order to increase the reliability of the simulation forecast, simulation models grew in size to a billion or more grid blocks, which poses a challenging complexity to build, validate, and history match the models. To help assess and handle new complexity and inherent uncertainties, an artificial intelligence algorithm based on Self-Organizing Maps (SOM) has been developed to explore and identify geologic model components based on similarities and dissimilarities in the model. Sector models can be generated based on these region definitions for focused region assessment, history matching, production/injection optimization, or optimal well configuration.

In this work, an unsupervised artificial intelligence neural network algorithm is devised that can combine both static properties distribution (permeability, Reservoir Quality Index (RQI), or porosity) and dynamic properties (pressures or saturations) to construct a similarities matrix. Standard deviation-based chaos minimization is then applied to merge similar regions (contiguous), identify similar but distant regions, and reduce the number of identified heterogeneous regions to the desired controlled number. The algorithm was applied on a synthetic reservoir model using the GigaPOWERS® simulator, The developed SOM-based algorithm conditions geology to reservoir dynamics, and reduce model computational requirements of assisted history matching (AHM) with minimal engineering effort.
Managing Crucial Business Decisions Related to a Wastewater Disposal System Using Hydraulic Simulation
Authors: Al-Ajmi Mohammed D. , Al-Hajri Nasser M. , Al-Subaie Fehead M.
Published: July 2016

Business decisions management in the petroleum industry is often constrained by a lack of representative projections, time limitation, and cost implications. Proper administrations of future amendments to existing facilities necessitate accurate predictions of proposed upgrades. The precise outcomes of hydraulic simulation have proven reliable in forecasting operational scenarios related to wastewater disposal (WWD) system. The accurate predictions of hydraulic simulation, coupled with identified time frames and monetary investments, pave the way for accountable and successful managerial decisions.

Increased water production from mature fields requires facilities to be upgraded to meet future business demands. WWDs are integral constituents of oil processing facilities as they are the conduit for responsible and environmental disposal of produced water.

Facility-A injects wastewater into five disposal wells at a given capacity. Production demands have increased, which subsequently, entail the need to avail extra injection capacity to Facility-A. Long-term plans to an entire system upgrade are well underway; yet, the demand for extra potential is imminent. Many short-term plans were conceptualized to meet the injection requirements in the interim period until the long-term upgraded facility is on stream.

A hydraulic simulation model was built and calibrated for Facility-A as a baseline model. Full system analysis of Facility-A disposal network, utilizing hydraulic simulation techniques, was performed to predict the outcome of each proposed short-term scenario. The contemplated scenarios were tapping into a nearby facility's disposal system, installing temporary injection pump at the wellheads, and adding two more injection wells to a new pipeline network.

This paper will present in depth the hydraulic simulation results of the abovementioned scenarios and highlight their feasibility as viable short term scenarios. In addition, a detailed account of the associated time periods and respective costs of conceived short-term plans is going to be shown.
A Comprehensive Geomechanical Study to Understand Drilling Challenges in the Manifa Field Offshore, Saudi Arabia
Authors: Ahmed Mujahed , Al-Shehri Hisham A. , Haidary Saleh A. , Povstyanova Magdalena
Published: July 2016

Saudi Aramco has been producing from the Manifa offshore field in the Arabian Gulf since 2011. By drilling mainly lateral wells, Saudi Aramco has targeted the main reservoir that belongs to the early Jurassic period. The pay zone is overlaid with weaker interbedded sand/shale formations and carbonate formations of the upper and lower cretaceous period.

The main challenges that were encountered while drilling these wells included total/partial mud losses and severe wellbore instability-related issues across the weaker formations overlaying the reservoir section (pay zone). An advanced geomechanical study was crucial for understanding the nature of the existing problems faced during drilling and applying the study's findings for drilling future extended reach (ERD) wells successfully.

A comprehensive geomechanical study of the field was conducted by constructing a calibrated post-drill 1-D Mechanical Earth Model (1D-MEM) for selected vertical wells. The study helped in providing reliable rock mechanical properties and fracture gradients across the problematic formations, a lack of which was a limiting factor in understanding the nature of the problems while drilling.

For the current study, an integrated workflow was implemented mainly to perform a root cause analysis of mud losses and to define well inclination (deviation) limits to drill through the problematic formations to minimize wellbore instability-related issues. Open hole log data was used to construct the 1D-MEMs. The developed models were further calibrated using all the available data (drilling observations, results of well testing, core mechanical testing, etc.). Image data was also analyzed to capture the presence of fractures/faults or related features along the wellbore.

Based on the analysis results, it was concluded that the mud losses in the overlaid carbonate formations were attributed to the presence of localized open natural fractures or caverns, or vugs. It was also concluded that most of the wellbore instability-related issues (hole pack-offs, stuck pipe incidents, etc.) occurred due to insufficient drilling mud weights that were not able to support the rock on the wellbore wall. The present study helped in better characterization of the problematic formations and also provided useful information for planning future extended reach (ERD) wells. Some of the provided recommendations included acquisition of micro resistivity image logs (to identify nature of fracture), implementation of real-time geomechanics, and optimization of mud rheology, mud weight program, and casing design.
Prediction and Management of Scale and Corrosion in a Harsh Operating Environment: Challenges and Innovative Solutions
Authors: AlGhazal Mohammed A. , AlKhowaildi Mustafa A. , Al-Driweesh Saad
Published: July 2016

Prediction of scale and corrosion in the oil and gas industry provides a valuable mean to address some of the most pressing challenges in field operations. Based on scale and corrosion tendency tests, a custom-built well integrity program can promote safer and more environmentally friendly production operations.

This paper presents practical techniques to predict potential scale and corrosion issues in a sour gas-producing field, and discusses control methods. The focus of this study is on the high pressure, high temperature deep horizontal wells that have been intensively acid fractured for economic production of tight gas. Scale precipitation is anticipated by geochemical analysis of produced water, including water hardness, limiting factor ion and stability index. Corrosion tendency is evaluated using laboratory tests simulating the acid fracturing treatment conditions.

Suspected scale and corrosion can be managed by applying a set of mitigating techniques, including selection and manufacturing of downhole completion equipment tubulars and accessories, acidizing treatment recipe and mixing guidelines, chemical inhibition selection and placement, as well as post-treatment over-flushing and flow back best practices. Innovative technological mitigating solutions include electro-kinetics technology, where more acid is consumed deeper inside the formation and a corrosion-sacrificial aluminum anode is incorporated. Also, the role of nano-sized additives in managing oxidizing reactions to enhance corrosion resistance is discussed. Field experiences have demonstrated that these strategies are effective in managing scale and corrosion, creating opportunities for asset reliability and operational excellence.

The novel technologies and operational guidelines discussed in this paper represent a holistic approach for operating companies to sustain tight gas production in spite of harsh scale-prone, corrosive operating conditions.
Business Intelligence Revolutionizes History Matching Process
Authors: Al-Ghamdi Reema , Al-Taiban Ali , Al-Zahrani Tareq , Al-Harbi Bader
Published: July 2016

One critical step towards building accurate reservoir simulation models is to efficiently assess the quality of the model's history match through identifying discrepancies between historical data and simulation model output to assess the history match quality. The role of Business Intelligence in history matching is crucial as it easily helps simulation engineers mine and manipulate data, visualize plots, identify patterns and run statistical algorithms. The History Match Quality Check (HMQC) tool capitalizes on these techniques and provides the required procedures to perform qualitative and quantitative analysis for simulation results in an efficient manner.

The developed tool helps engineers graphically identify wells, or cluster of wells, with discrepancies in pressure and water-cut trend, and offer a wide range of flexibility to rank simulation runs according to history match quality. One of the main advantages of the tool is that it can load data from different database sources as it combines both historical data and simulation output in one platform, and guide engineers to perform necessary adjustments to achieve a better history match. The HMQC tool is a dashboard which provides several tabs primarily for the main history match parameters such as first water or breakthrough timing, last and water-cut deviation and pressure evolution. Moreover, it allows engineers to extract statistical information from the simulation runs for quality check purposes and examine how close the model represents the field/reservoir performance. The tool uses advanced statistical algorithms to estimate the simulated properties' trend based on well performance, including first water breakthrough, water-cut and pressure trend against historical data.

This paper explains the algorithms used in the HMQC tool that utilizes Business Intelligence data mining and visual analytics to enhance and streamline the history match process.
An Experimental Study of Interfacial Tension and Contact Angles of CO2/Brines/Surfactants/Oil Systems with Dolomite Rock
Authors: Mahboob Ahmad , Sultan Abdullah S.
Published: July 2016

In this work the effects of different parameters such as surfactant type, salinity, temperature, pressure and oil type have been studied experimentally in the presence of CO2 at 30°C and pressures as high as 5000 psi for changes in interfacial tension and wettability with dolomite rock.

In the 1st step, IFT of four multicomponent brines of different salinities were compared and the brine showing lowest IFT with CO2 was used in the 2nd step for comparison of three different brine-surfactant solutions (BSS). The BSS with lowest IFT was then used to study the IFT behavior of three different oils with CO2. Last step consists of contact angle(CA) measurements of oil with dolomite rock in the presence of CO2 and BSS. Brines are multicomponent with salinities ranging from 8,500 to 67,000 ppm. Comparison of surfactants was among solutions of an alcohol-propoxysulfate surfactant, a viscoelastic surfactant and a fluorosurfactant.

IFT of brines increase with increase in salinity and temperature and decreases with increase in pressure. This is due to solubility of CO2 in brine. Out of the three surfactants, most soluble solution is a fluorosurfactant and gives ultra-low IFT with CO2. This BSS of florosurfactant when used with oil, forms pressure-sensitive microemulsions in CO2 causing the IFT of the oil to decrease. CA of oils with dolomite rock increase with pressure in the presence of fluorosurfactant and CO2.

In the literature, comparison of IFTs of different surfactants in CO2-Brine systems, Brine-Oil systems, Surfactant-CO2 systems, and surfactant-oil systems have been reported but this work reports on all CO2/Brine/Surfactant/Oil/Dolomite co-existing which can help in planning a Surfactant-Alternating-Gas(SAG) or Water-Alternating-Gas(WAG) process more accurately.
Shallow Gas Drilling in North Safaniya, Saudi Arabia: Challenges, Lessons Learned & Recommendations
Authors: Alghamdi Magid A.
Published: July 2016

Safaniya Field is the largest offshore oil field in the world. This field was discovered in 1951 and is located in the Saudi section of the Arabian Gulf. In recent years the importance of Safaniya field has increased due to oil demand and therefore the drilling of new wells has also risen. This field has been divided into three parts: North, Center and South. In the Northern section of this Field, shallow gas formations present a major concern for drilling operation. This gas flow from the shallow formation carries with it high volumes of abrasive sand production of varying sizes from small particles to boulders. This gas has also shown a tendency to bubble through the sea floor, which may result in the formation under the platform or the jacks of the offshore rig to subside and thus taking the risk of a catastrophe that will result in losses in facilities and life.

Other challenges include gas migration in the annulus due to reduction in the hydrostatic pressure (insufficient mud weight, mud losses …etc.) or bad cement isolation of the annulus between the casing and the open hole that will cause channeling in the cement.

This paper describes the challenges encountered in North Safaniya field. In addition, the paper will discuss the lessons learned and the best practices that have been applied. Finally the paper gives recommendations for minimizing and preventing future challenges to arise which include changing the casing design to a more optimum option that will provide more secure isolation of the troublesome formation.
A New Polymer System for Water Shutoff Application in Carbonate Formations
Authors: Almohsin Ayman , A-Nakhli Ayman , Badairy Hameed , Alabdrabalnabi Mohammed , Hung Jin , Bataweel Mohammed
Published: July 2016

Excessive water production from hydrocarbon-producing wells can adversely affect the economic life of the well. It was estimated that an average 2.8 barrels of water is produced for each barrel of oil worldwide. Unwanted water production can unfavorably affect well economics owing to handling of the produced water, reduction of hydrocarbon production, and environmental concerns. Naturally, fluids tend to follow in paths of least resistance which, in reservoirs, are often created by the heterogeneous nature of the rock. There are two levels to this heterogeneity; primarily, microscale heterogeneity which could be represented as a simple porous feature distribution; and the second is macroscale heterogeneity which includes layering, natural or induced fractures, and high vertical and horizontal permeabilities. Together can lead to poor conformance and thus need to be corrected. If fractures for water path are in present, then they need to be plugged in order for producing wells to remain in operation.

Numerous chemical options are available for addressing excessive water problems. Most of these chemicals are more suitable for Sandstone formations rather than carbonate rocks. It is estimated that carbonate reservoirs restrain more than 60% of the remaining oil worldwide. The objective of this work is to investigate the efficiency recent developed chemical material for carbonate formation. This material presents an innovative technology for both fracture and Supper-K water shutoff agent.

An Integrated approach was applied to investigate the efficiency of a new polymer system (a novel adsorption system). A core flooding tests were conducted to evaluate the effectiveness of this chemical system using super-K, and fractured core. An analytical study, environmental scanning electron microscopy (ESEM) and energy dispersive X-Ray microanalysis techniques were applied to characterize untreated and chemically treated core plug samples.

The core flow testes indicate significant drops in water production of all high permeability, fractured and wormholed formation. When chemical treatments were placed, the polymer system was able to withstand the differential pressures and did not allow the flow of water in wormholed core, high permeability cores and fractured core. The ESEM results showed the presence of C-rich compounds filling fracture. This suggests that the chemical treatment of the core plug has resulted in some of the used polymer product blocking fractures and pores.
Case Studies of Hydraulic Wet Connect System for Pod ESP and Intelligent Completion Applications in Multilateral Wells
Authors: Dossary Khalid A. , Jacob Suresh , Muhaish AbduRazzaq , Shafiq Muhammad
Published: July 2016

Saudi Aramco has installed over 64 hydraulic wet connect (HWC) tools to combine smart well completions (SWCs) with electrical submersible pumps (ESPs) over the last 6 years. These completions are installed for remote inflow control in Maximum Reservoir Contact (MRC) and Multilateral (ML) wells in Saudi Arabia fields. This paper describes case studies of HWC completion options, design, and installations, including several successful replacements of ESP in such wells.

Intelligent completions were nearly started 15 years ago to provide selective zonal/lateral control, delay water breakthrough, control water production, shut-off wet zone/lateral, reduce operational expenditure (OPEX), enhance safety by minimize intervention, optimize production and/or enhance recovery.

The HWC system provides two main advantages. 1) The first advantage is to replace the ESP when required without the need of retrieving lower intelligent completions system, which saves both workover-rig time and ultimately cost. 2) The second advantage is to complete extended reach (ERD) with shallow TVD to install completions in two stages: The first stage is to install lower intelligent completion with receptacle and drill pipe to reach TD. The second stage is to install upper completion with stinger and tubing as per the design, and calculations of torque and drag to establish communications with lower intelligent completion.

In several wells, upper completions have been successfully recompleted with ESP. Therefore, the technology has proven its real value, especially in an offshore environment.

This paper will cover case histories, best practices, lessons learned and new advancement in HWC and related technologies.
Assessing the sensitivity of SWAT physical parameters to potential evapotranspiration estimation methods over a coastal plain watershed in the southeastern United States
Authors: Samadi S. Zahra
Published: July 2016

One of the key inputs of a hydrologic budget is the potential evapotranspiration (PET), which represents the hypothetical upper limit to evapotranspirative water losses. However, different mathematical formulas proposed for defining PET often produce inconsistent results and challenge hydrological estimation. The objective of this study is to investigate the effects of the Priestley–Taylor (P–T), Hargreaves, and Penman–Monteith methods on daily streamflow simulation using the Soil and Water Assessment Tool (SWAT) for the southeastern United States. PET models are compared in terms of their sensitivity to the SWAT parameters and their ability to simulate daily streamflow over a five-year simulation period. The SWAT model forced by these three PET methods and by gauged climatic dataset showed more deficiency during low and peak flow estimates. Sensitive parameters vary in magnitudes with more skew and bias in saturated soil hydraulic conductivity and shallow aquifer properties. The results indicated that streamflow simulation using the P–T method performed well especially during extreme events’ simulation.
Scarcity to solution: perceived reasons for safe drinking water scarcity and local coping responses in a coastal village of Bangladesh
Authors: Imam Md. Ali , Haque Md. Zahidul , Yunus Samiha
Published: July 2016

People are directly and indirectly exposed to changing weather patterns through changes in the quality of water, air, and food changes in ecosystems, agriculture, industry, human settlements and the economy. Hence, this study explored local perceived reasons for safe drinking water scarcity and under such circumstances the coping responses in their region. This is a descriptive study based on qualitative methods. Male and female informants (30 + years of age) were purposively identified and data for the study were collected in three ways, through observation and informal discussion, in-depth interviews (n = 18), and three focus group discussions in a coastal village of Bangladesh. Climate change consequences include damaged trees and increased salinity intrusion, leading to a scarcity of safe drinking water. To cope with such scarcity of water, small scale road side mangrove tree planting was found to protect fresh water from salt water. In addition, cost effective rainwater preservation in the community during the rainy season was taken as mitigation of the scarcity of safe drinking water. Considering the geographical and socio-economic context of any specific region, cost effective and environment friendly local adaptive measures can reduce or mitigate the impact of climate change on water resources.