bluuebunny/crossref_metadata_2025 huggingface dataset:
Non- Coiled Tubing Stimulation of Water Injectors
Authors: Mahmoud M.A. , Abdelgawad K.Z. , Akram A. , Stanitzek T.
Published: March 2015

Sea water is injected to maintain the reservoir pressure that supports the oil production from carbonate and sandstone reservoirs. The Gulf sea water contains more than 4000 ppm sulfate and the formation contains more than 19000 ppm calcium, this will cause calcium sulfate precipitation at the reservoir conditions. The precipitate at the reservoir conditions will be anhydrite and it will cause formation damage that will reduce the well injectivity. Stimulation treatments are required to recover the well injectivity and this requires stopping water injection to perform the stimulation treatments.

In this study we are proposing a new method that we can use to stimulate water injectors without stopping the water injection. The new method includes adding a chelating agent to the injected sea water at the well head at 15 wt% concentration. Several solubility and coreflooding tests were performed using actual carbonate cores and the new chemical at different temperature ranges. The chemical injection does not need coiled tubing and can be injected at the surface with the sea water. The chelating agents will sequester all calcium in solution and will prevent the calcium sulfate precipitation. The chelating agent used in this study is GLDA.

Solubility tests up to 250°F at high pressure showed that the GLDA is stable with the sea water. Coreflood experiments and CT scans showed the ability of GLDA in the creation of nice wormholes through a 6 in. and 1.5 in. carbonate cores at 100 and 70°C respectively. The GLDA chelating agent can be used to stimulate sea water injectors without any additives as this chemical is stable and is gentle with the well tubulars. Previous corrosion studies on GLDA showed that its corrosion rate is in the allowable range without adding corrosion inhibitors.
Successful Downhole Sampling in HPHT Extreme Sour Exploratory Wells Using DST Sampler.-Case Studies
Authors: Al-Salali Yousef , Al-Bader Haifa , Al-Ibrahim Abdullah , Sagar Vidya , Manimaran A. , Packirisamy S. , Rajkhowa Anupam
Published: March 2015

Jurassic reservoirs in Kuwait fields are deep (upto 17,500 ft), high-pressure (>10,000 psi), high temperature (300°F) and having high H2S concentration upto 35%. Additionally, some reservoirs are having super saturated saline water. Exploratory wells drilled in these reservoirs are tested with Drill Stem Test (DST) tools. High quality reservoir fluid sample is necessary for meaningful PVT studies, which is very important for assessment of reserves and for future development. Many wells were tested in deep reservoirs but BottomHole Samples (BHS) could not be collected in most of the wells due to extreme well conditions namely well deviation, HPHT, H2S upto 35% and salt deposition inside tubing. Generally, Well Head Sample (WHS) and/or separator samples are collected for PVT studies. Downhole samples are preferred for carrying out PVT studies. However, using slick line/wire line for collecting downhole samples was considered unsafe and having potential risk due to extreme well conditions. Keeping in view of well profile and hostile environments, provision was made to collect representative reservoir fluid sample using downhole sampler in DST assembly. The DST sampler is rated to 20,000psi and 400°F, can collect upto nine 400cc samples, and are activated in sets of three by annulus pressure. It was very challenging to operate the downhole DST sampler, as the mud used in the annulus was as high as 20.8ppg OBM.

A pilot study on this DST sampler was implemented in two different exploratory wells. Reservoir fluid samples of sufficient quantity were collected at downhole condition in hostile environment. Quality of samples collected during DST is good and these samples were used to characterize the reservoir fluid. Based on the successful results, it has been planned to use DST sampler in these hostile environment in future.

This paper describes successful downhole sampling DST design/tools, together with the techniques implemented to obtain representative reservoir fluid samples at downhole.
Facies Architecture, Channel System and Paleoflow Pattern of a Young Sandstone Reservoir using Borehole Resistivity Images
Authors: Ahmed Khalid , Ferdous Hasan , Choudhary Pradeep K , Abbas Faisal , Al-Khamees Waleed , Helba Adly , Osman Adham , Ali Wael , Fatah Mohsen Abdel , Vasquez Rafael
Published: March 2015

The Miocene age shallow unconsolidated sandstone formation in Kuwait contains viscous oil whose distribution is primarily controlled by depositional facies and their diagenetic modifications. This study integrates core-calibrated resistivity images with openhole logs to obtain high-resolution facies logs with continuous array of oriented depositional structures, facies types, and environment-related facies associations with paleocurrents measurements. These are combined in defining reservoir zonation, geometry, spatial distribution and paleo-geographic evolution during its accretion across the field.

The formation is characterized by variable grain sizes, sedimentary structures and diagenetic cementations. The sandstone succession is punctuated by scouring surfaces and separated by discrete mudstone intervals mixed with scattered bioclasts. The upper section of the formation encompasses two main oil-producing sandstone intervals (S1 & S2 reservoirs), separated by a mudstone unit (Mid Shale) and sealed on top by marine Cap Shale unit. Each sandstone interval consists of lower sheet-forming stacked horizontal-and cross-stratified sandstone units (S1B & S2B) and upper lenticular sand-prone bodies (S1A & S2A) that laterally truncate or intermingle with units of sandy mudstone and argillaceous sandstone (S1 Shale & S2 Shale).

The observed physical and biological features, paleocurrents data and vertical hierarchy of recognized sandstone and mudstone facies suggest the oil-bearing sequence formed as fluvial to upper delta-plain deposits that were accreted by repeated lateral shifting, and an overlapping of fluvial channels, distributary/abandoned channels, crevasse splays and inter-distributaries lakes or bays of estuarine origin. The active fluvial-and distributary channels were generally flowing from SW to NE, and locally due E and SE, and largely discharged from S. The morphological parameters reveal that the fluvial channels migrated laterally and bifurcated downstream, and fluctuated across a low sinuous channel belt. With continuous base level rise, the area was drained entirely by transgressive brackish-water lacustrine or bay events depositing the widely distributed Mid-Shale and Cap-Shale units.
Integrating Flexibility in New Development to Formulate Optimal Depletion Strategy with Reduced Risks in a Complex Carbonate Reservoir in Middle East
Authors: Vinayagam Vinoshen
Published: March 2015

The field of interest is an anticlinal structure aligned Northwest-Southeast, about 31 km long and 10 km wide. The field was discovered in 1984. The major reservoir, M is further subdivided into M1, L1 and L2. It is a carbonate reservoir containing approximately 75% of the total field Stock Tank Oil Initially In-Place (STOIIP). Other reservoirs are Y, Z and R.

The biggest uncertainty in preparing a Field Development Plan (FDP) for the field is the subsurface uncertainty due to limited data availability. Areal and vertical heterogeneity are evident even from the early production data. These came at no surprise as available core data, well testing data and other pressure data suggest the same.
“Oil Spillage Environment Impact Reduction Based On Automated Leak Detection on Rod Pumping Wells in South of Oman”
Authors: Mahrooqi Salim Al , Gonzalez Maximiliano , Marcano Miguel , Vargas Luis , Harthy Abdullah Al
Published: March 2015

The environmental impact of oil spillage and additional costs associated in oil fields is an important matter, especially in large oil fields, where well sites monitoring and spills prevention are not easy tasks; therefore a new spillage management detection is an utmost required.

Petroleum Development Oman (PDO) has more than 1700 Beam lift wells operating in the South Oil Directorate. In the latest years the Stuffing Box (SB) leaks have become a serious issue in field operations, causing a severe environmental impact as well as a significant additional operational costs and unscheduled production deferment.

In most of the cases the SB leaks are related to wellhead or Beam Pumping surface unit misalignment, which somehow affect the mechanical condition of Polished Rod (PR) limiting its run life. When the PR is not aligned with the axial bore of the SB a lateral force exerts upon the SB by the PR is producing severe wear and premature failure of its rubbers elements resulting in SB leaks. In many cases when the SB leak begins, the spillage get overflow on the location resulting in an environment damage and unnecessary deferment due to BP outage.

Solution to the above problem lies in automation, which is also key success factor in every phase of oil production process. It allows production processes monitoring, as well as its optimization and controlling, aiming to reduce costs and maximizing the overall system efficiency. The tangible and intangible savings generated by these automation systems have exceeded customer/operator's expectations in all cases, where spills have been significantly reduced and early SB leaks have been successfully detected and corrective action there upon taken.

This paper gathers the results of field investigations conducted to understand causes behind of SB's integrity loss, which might lead to severe fluid spillage on well locations. Furthermore, presents the new operational philosophy, which could reduce company exposure in terms of HSE risks and additional operational costs associated with management of oil spillage.
Developing Risk Profiles for Produced Water Re-Injection Utilising Advanced Imaging Technologies
Authors: Bhola N. , Ariaratanam G. , Roth N.
Published: March 2015

Online particle measurement is one of the key technologies in characterising fluid quality and developing strategies to ensure the efficient operation of and optimise any separation process. Online imaging systems have the benefit of being able use their multi-dimensional data to provide more information than just particle size, as particle shape, aspect ratio and many other parameters measured can be used to identify and classify different types of particulates, such as oil droplets and solid particles in a produced water system.

This understanding of particle type, size and shape provides a significant step forward over simple particle size as it enables separation process design and operation to specifically treat and remove target particulates. In this paper we will examine case studies that demonstrate how specific particle information can be used to understand and optimise different treatment stages within a produced water treatment system.

Agglomerates appear frequently in some fluid systems and can confuse imaging systems where simple parameters are being used to differentiate between particle species as the agglomerated material will present with different shape characteristics to those of its individual constituent particles. We will review produced water systems where the chemicals used to aid separation, and some of the separation technologies themselves, operate by creating aggregation and agglomeration using case studies demonstrating these effects. We will discuss where agglomerates commonly occur and what significance these particles have within the oily water separation process. We will review the latest imaging software package that is capable of identifying these types of agglomerated particles and assessing constituent components.

Finally we will assess how this information contributes to our understanding of the risk profile that these types of agglomerated materials present in produced water re-injection and how that risk profile may be developed and analysed in the future.
A Decade of Experience with MPFM in Northern Fields of Saudi Aramco
Authors: Al-Kadem Mohammad S. , Al Khelaiwi Faisal T. , Al Mashhad Ali S. , Al Dabbous Mohammad S.
Published: March 2015

Multiphase flow metering is considered one of the most essential technologies in well testing. Since the mid 1990's, Multiphase Flow Meters (MPFM) have evolved from a revolutionary new technology into a consolidated solution widely adopted by the major operators worldwide. This evolution has taken place thanks to the high quality of measurements, low operational cost and the capability of enabling remote monitoring of wells' performance and testing with ease.

The installed MPFMs in Northern fields of Saudi Aramco have contributed effectively to enhancing the semi-real time measurements' quality as well as improving reservoir characterization. Though, MPFMs are prone to mechanical and firmware failures. The MPFM technology largely seems to be performing as expected and delivering high quality data. So far, 58% of the systems have been in service for more than 8 years and continuing to operate efficiently.

Thorough analysis of the routine maintenance and checkups conducted during the past 10 years revealed the following:

The MPFMs Mean Time between Failure (MTBF) and Mean Time to Repair (MTTR) indicated that the MPFMs have been available 97% of the time. The use of a probabilistic approach (Monte-Carlo™ Simulation) to study the P10, P50 and P90 values of the maintained MPFMs indicated that the variance between these values is small, demonstrating the reliability of these equipment. The classification of the diverse types of problems faced while operating the MPFMs highlighted the dominant cause of failures and enabled the initiation of a surveillance and subsequent failure mitigation program.

This paper discusses the lessons learnt and experience gained from operating 168 MPFMs provided by different vendors in different environments during a 10-year period, along with the appropriate solutions that were implemented to mitigate the challenges faced and subsequently improve the efficiency and data quality of the MPFM.
Extensive Fracture Diagnostic Tests and Customized Workflow Lead to Successful Characterization of Deepest Unconventional, Tight and Sour Dolomite Formation in North Kuwait
Authors: Al-Zaidani Ibrahim Mahamed , Barasia Ankur , Al-Failakawi Abdul Aziz , Fidan Erkan , Sharma Siddhartha Shankar , Samad Zamzam Mohammed , Khayan Andre
Published: March 2015

Appraisal program of the deep gas/light oil from unconventional reservoirs in North Kuwait is strategically important to secure the challenging hydrocarbon production targets of Kuwait Oil Company (KOC). A very deep high-temperature/high pressure (HT/HP) dolomitic formation is at approximately 15, 000 ft (vertical), poses complex completion and producibility challenges. Exhaustive log suite and core analyses confirm some porosity development and gas shows. Unlike the proven carbonates up-hole in the same asset, the deepest dolomite units have extremely low permeability, and may not flow unless enhanced by a natural fissure network and/or hydraulic fracturing.

Only a few wells have been attempted for completion in these deepest dolomite layers, which failed to flow even after matrix acidizing treatments. The effective completion design will require good understanding of formation mechanical properties and fluid leakoff behavior, leading to optimal horizontal wells to maximize reservoir exposure completed with multiple hydraulic fracturing treatments to establish hydrocarbon production at commercially acceptable rates. Therefore, properly designed and effectively executed extensive fracture diagnostic tests are critical in the current pre-appraisal stage. In addition, multiple acid-fracturing treatments have already contributed to the understanding of fracture geometry development and fracture flowback characteristics.

A fracture diagnostics workflow was developed and deployed to appraise the deepest dolomite layers. Critical fracture mechanics data were collected and analyzed. The main fracturing treatments have also yielded crucial results, which will help the design team in optimizing the horizontal well completions. This comprehensive workflow can be successfully applied in characterizing challenging formations elsewhere where the well and regional data are limited in the appraisal of similar light oil/tight gas-bearing unconventional carbonates.
Knowledge Transfer-Lessons Learnt - A Case Study of Kuwait Oil Company
Authors: Al-Daihani Eisa Hadi , Nandi Arun Kumar , Raza Syed Mohammad
Published: March 2015

Competent Manpower always considered as a big challenge in rapidly transforming business environment. Traditionally, most of the National Oil Companies are dependent on training providers for their technical staff development. However, most companies are judicious in identifying the competency gaps within their employees through either available Competency Management System or customized system. Once they identify the gaps, various training options like basic, advance courses, workshops etc. are being delivered through training providers. However, there are concerns related to the quality assurance and competency gap fillings (for selected learning options) keeping in view of the company's strategic business needs and vision.

In order to make the competency development process more effective with quality assurance on their gap fillings, Kuwait Oil Company in the past three to four years has come out with a new approach of engaging their internal resources for knowledge transfer. These internal resources are subject Discipline Experts (DEs) available within the company who knows the business needs of the company. Human resource development is a business-driven function and its effectiveness depends on thorough understanding of organization's strategic direction.

The present paper focusses on an approach of knowledge transfer and lessons learnt through identification and engagement of senior employees as DEs with proven track record of coaching/mentoring abilities. The DEs are being proved as most effective and powerful resource to develop not only the new hires but also the mid-career employees. DEs have established a comprehensive job family wise customized competency matrix based on critical business need of the company. The approach has also helped the company in fast track development of technical manpower and filling generation gaps between large number of new hires and aging available technical expertise. This has proved to be a cost effective approach with win-win situation for the employer and employees.
The Influence of Pressure on the Low Temperature Oxidation (LTO) of Heavy Oil During the High Pressure Air Injection(HPAI)Process in Tahe Oilfield
Authors: Li Yi-Bo , Cheng-Yuan Dong , Pu Wan-Fen , Jin Fa-Yang , Chen Ya-Fei , Li Dong , Zhao Jiang-yu , Zhao Jin-Zhou
Published: March 2015

With the decline of conventional oil production, developing and producing heavy oil resources efficiently are becoming more important. High pressure air injection (HPAI) is generally considered as an efficient method to drive the crude oil in light oil reservoir. But there is a debate about whether the released heat from oxidation reaction is able to activate the heavy oil effectively. Comparing to the in-situ combustion (ISC) technique, air injection without ignition will reduce the operation difficulty and eliminate the security risk. Thus studying the changing of the oil property in presence of injected air is the prerequisite to apply the HPAI technique in heavy oil reservoir. For this purpose, the constant temperature oxidation experiments have been carried to study the influence of pressure on heavy oil in the air injection process at reservoir condition of Tahe oilfield.

The results showed that the pressure has obvious influence on the crude oil property. By the increment of pressure, the oxygen in the air presented a decreasing trend while the amount of carbon dioxide did not exhibit an increasing trend. The oxidation addition reaction dominated the reaction type. For the oil phase, the viscosity of the oxidized oil presented a slight decrease under relative low pressure condition. When the pressure reached 50MPa, the crude oil has transferred into coke completely. During the oxidation process, the property and amount of the coke directly related to the released heat amount in the high temperature oxidation (HTO) stage. According to the thermogravimetry (TG) and differential scanning calorimetry (DSC) results, the oxidized oil achieved lower HTO trigger temperature. So it is believed that the higher pressure has a positive influence on the coke deposit process. The formation of sufficient coke will bring the possibility for the application of HPAI technique in heavy oil reservoirs.
Gravity Drainage Effects on Compositional Displacements in Fractured Reservoirs
Authors: Alhamdan Mohammed R. , Cinar Yildiray
Published: March 2015

This paper investigates the effects of gravity drainage on non-equilibrium compositional displacements in naturally fractured reservoirs (NFRs) by presenting an experimental and numerical simulation study. A quasi 2-D glass bead pack is used to represent a NFR. The matrix and fracture are represented by glass beads and a grooved glass strip, respectively. Conductive fractures are studied. An analogue ternary fluid system (isooctane, brine and isopropanol) is used to control the interfacial tension (IFT) between the phases at ambient conditions. Immiscible, near-miscible and miscible floods are studied. Recovery of phases, compositional analysis and snapshots of saturation distributions are reported. Numerical simulations are used to interpret experimental observations.

In immiscible displacements, capillary forces are found to be the main controlling factors for the vertical cross-section reservoir model while a balance between capillary and gravity forces governs gravity drainage displacements. In miscible displacements, the balance between gravity and viscous forces controls sweep efficiency and recovery factor for both reservoir models. Near-mmiscible miscible floods give higher recovery than first-contact miscible floods under gavity drainage. This opposes to the observation made for the horizontal floods. This is in line with the finding reported in the literature using numerical simulations.

Force-balance scaling criteria (i.e. capillary, gravity and Bond numbers) diagnose flow regimes during displacements satisfactorily. Black oil simulations sufficiently predict experimental observations of all displacements examined provided that history-matched capillary pressure and relative permeability are used. Compositional analysis of the effluent indicates that the compositional path changes between tie-lines of initial and injection liquids based on saturation profile development.
Successful Partnership to Rejuvenate a Mature Field
Authors: Zubari Hisham , Kershaw Andrew , Qassab Mohammed Al , Muhanna Nadeem
Published: March 2015

The Bahrain field, first discovery in the southern part of the Arabian Gulf region, has been on continuous production since 1933. Production peaked at 78,000 bopd in 1970. Although many reservoirs have reached mature stages, considerable volumes of oil resources remain unexploited due to the difficult nature of the rock and fluids, complicated by heterogeneities, complex fluid distribution, unfavorable rock-fluid characteristics and compartmentalization, to name a few.

The keys to unlock the potential of the Bahrain field lie in 1) understanding surface and subsurface production problems of each of the reservoirs1, 2) attracting the right expertise in the field of Enhanced Oil Recovery (EOR), and 3) attracting large investments to debottleneck and expand facilities, test EOR pilots, and implement new technologies2.
PCPs Coming of Age as a Viable Artificial Lift Solution for Low API Crude Fields
Authors: Agarwal Soham , Aggarwal Avi , Kumar Avinav
Published: March 2015

Majority of the Indian Oil Fields have gone well past the age of self-flow, with only a very few select wells currently producing crude utilizing the natural reservoir energy. It is a well-documented fact that the age of easy, light oil has passed and that, most of the new discoveries being made are those of either heavy or ultra-heavy crude oil types.

SRPs, ESPs, Jet pumps, Gas lift are the various modes of artificial lift currently under employment. However, all these methods fail when heavy oils are encountered. In such cases, these methods of artificial lift fail to provide the requisite lift for the crude to reach the surface. However, the Progressive Cavity Pumps (PCPs) have found great utility under conditions of heavy crude production. The spiral motion of the Pump cavity from suction to discharge causes jerk-free motion of the crude.

PC Pumps have distinctive advantage over the other methods, when heavy crudes along with significant sand cuts are to be produced. PC Pumps are also used on a large scale for de-watering of CBM wells.

In this paper, an extensive review of the available literature was done to study PC Pumps and the various advancements achieved through the years. Artificial lift selection methods were investigated and a comprehensive procedure enlisted to select the right type of lift which best suits the field/well.
Fracturing Design Optimization through Dimensionless Productivity in the South Sulige Field
Authors: Wong A.K. , Judd T.C. , Palacio J.C. , Wong K. , Fan W. , Grimbert B. , Wang Q. , Hu L.
Published: March 2015

A field development project in the central part of the Ordos Basin began in 2011 with the intent to develop commercial production from the two main gas producing intervals. The gas layers within the Shihezi and Shanxi Formation within the South Sulige field are low permeability (0.1 mD) with moderate volumes of gas in place that require hydraulic fracturing to be commercially viable. The early application of technology to minimize development costs and surface impact included multiwell pad-drilling to enhance drilling, completion, and operational efficiency. Fracturing cycle times were reduced by the implementation of multiwell hydraulic fracturing processes, while not compromising well productivity.

To date, 33 well pads have been completed which represents more than 280 vertical wells and 13 horizontal with more than 600 hydraulic fracturing stages being done within the previous three years. The wells completed have encountered a largely heterogeneous field that has resulted in a sizable amount of data being collected.

To improve on this phase of the project, a fieldwide study of fracturing performance has been performed and includes the quantification of dimensionless productivity index (JD), dimensionless fracture conductivity (CfD), and dimensionless proppant number (Np). This analysis was performed on various well types, completions types, and fracturing design approach to benchmark performance. Analysis shows some improvements were made since the initial years of the project with designs starting to approach an optimum, but more significant advances can be made. Subsequent design adjustments and well optimization were done with improved understanding of postfracture performance derived from fracturing performance type curves.

This paper will discuss the optimization of the fracturing design through use of JD. The discussion will mainly focus on the use of the JD type curves and accumulated production performance to determine optimal proppant and half-length for improvements in future fracturing designs.
CO2 Injection Project Analysis Using Application of Integrated Model and Optimization
Authors: Rahmawati Silvya Dewi , Hoda Mohammad Faizul , Kuntadi Arif
Published: March 2015

Carbon Dioxide (CO2) injection is a common process used to increase hydrocarbon production in oil and gas fields, which is known as the enhanced oil recovery (EOR) process. This paper presents modeling of a carbon capture, utilization and storage (CCUS) project using an integrated operation and optimization approach.

In this case study, the subsurface system consists of two different reservoirs, a gas condensate and an oil reservoir. The products from the two reservoirs are processed in a single surface processing facility. The CO2 will be captured from both reservoirs and injected into the oil reservoir after being processed in the surface facility. The CO2 from various capture processes will produce different types of residual components, and the effects of different compositions of the injected CO2 stream on field economic revenue will be studied. The verification of extra cost by increasing the CO2 mole fraction in the recycle system is modeled in the economic cost equation. The final surface separation products will be condensate (oil), natural gas liquid (NGL), and sales gas.

Various derivative-free optimization methods will be used to maximize the net present value (NPV) of the CO2 EOR project. The decision variables are the multi-stage separator pressure conditions (surface parameters) and the CO2 injection rate (sub-surface parameter). Optimization results using different optimization methods will be compared to determine the best field operating parameters. The possibility of combination with water injection will also be investigated to determine the best injection scenarios.

An integrated analysis of the CO2 injection process provides a thorough and comprehensive understanding of the performance of the complete CO2 injection value chain. Optimization at the field scale provides insights into the subsurface response to field scale parameter variations. The integrated approach presented in this paper will provide a basis to evaluate CO2 EOR scenarios compared to other injection strategies, such as surfactant or polymer injections.
Productivity Index Prediction for Oil Horizontal Wells Using different Artificial Intelligence Techniques
Authors: Alarifi Sulaiman , AlNuaim Sami , Abdulraheem Abdulazeez
Published: March 2015

In the production aspect of petroleum engineering, Productivity Index (PI) is considered as a key parameter to develop the inflow performance relationships (IPR). It estimates and forecasts the well productivity and production efficiency. The current practice to obtain PI is to conduct a rate or well test in a producing well after which the PI can be calculated. Many correlations have been developed to predict PI for horizontal oil wells using reservoir and well properties before drilling wells for planning purposes to effectively build and estimate the production system of the well.

Artificial intelligence (AI) techniques have been used in the industry to enhance the engineer's ability to forecast and predict the many different and high uncertain outcomes of many of the petroleum industry aspects. AI methods have proven its accuracy for many cases and have been used as successful tools by many oil and gas companies. Prediction/forecasting using AI is a well-known practice and very essential requirement toward a better and more productive industry.

This paper discusses and shows the ability of three artificial intelligence methods (Neural Networks, Fuzzy Logic and Functional Networks) to predict productivity index of horizontal oil wells with very good accuracy as compared to several well-known correlations in the industry (Borisov, Giger-Reiss-Jourdan, Renard-Dupuy, Joshi and Economides, Butler and Furui). It discusses, for the first time in the oil industry, the application of the Functional Networks AI techniques in prediction PI of the horizontal oil wells. The models are built using several real field rate tests collected from more than 100 different horizontal oil wells from a field in the Middle East. Also, models showed to overcome the limitations of existing horizontal wells' correlations with high validity of the prediction due the presence of actual field data, not just assumed/simulated data.
Characteristics and Inversion Point of Heavy Crude Oil Emulsions in Kuwait
Authors: Ghloum E.F. , Rashed A.M. , Al-Attar M.A.
Published: March 2015

This paper presents an experimental study on how to characterize the heavy crude oil emulsion necessary for the development of design basis. Heavy crude oil emulsions (as oil-in-water or water-in-oil) are generated through the production system starting from well bottom pump, gathering flow line network and fittings all the way to the process facility. Most of the cases, these emulsions are very challenging to be broken and this challenge could be very sharp with the presence of higher asphaltene content. Emulsions nature is an important aspect in the heavy crude business to look at it as this will determine the project feasibility (in terms of $/barrel oil treated).

The paper shows the stability and rheological properties of hot and cold-produced heavy crude oil emulsion samples over a wide range of operation and field conditions. Emulsion samples were first characterized including physical properties for both water and oil phases. A comprehensive testing program has considered a number of sensitivities such as: temperatures, demulsifiers dosage, mixing and shear rates and water cuts.

Through the lab results, it can easily be seen that cold-produced heavy oil emulsion (CP-HO) is very stable over the tested sensitivities. However, the addition of chemical dispersants has accelerated the water separation regardless the presence of demulsifier. Another important finding is that the inversion point of the CP-HO emulsion could not be seen over the water cut range tested while the hot-produced heavy oil emulsion (HP-HO) inversion point has been noted at around 60% of Water cut. Moreover, five different viscosity correlations were validated against the experimental data for one HP-HO emulsion sample at different water cuts. The results showed that the correlation described the experimental data quite adequately at low shear rate and low temperature.
Measures Not Monitored Cannot Be Controlled
Authors: Mirza Faisal A , Mohiuddeen Mohammad K
Published: March 2015

Most of us know the famous quote of Mr. Ducker “You can't manage what you can't measure”. This is very much applicable to every industry. Evaluation/Assessment and monitoring are important steps to ensure better performance for any activity. Likewise, for Health, Safety, Environment (HSE) there are different performance assessment parameters, monitoring methods, procedures and the related Management aspects. Selection of the performance parameters and assessment system is required to be more elaborate and comprehensive and must be on the risk-based system. Careful selection of HSE measures based on Risk-based approach is the stepping stone to achieve good HSE performance of any organization on continual basis.

Even today, it has been observed that organizations are evaluating/monitoring their respective HSE performance through only indicator i.e. Lost Time Injuries (LTIFR). Considering the current scenario in which the Industry continues to encounter new horizons and environmental pressures that are changing and challenging day after day, it is highly essential to choose indicators through which an Organization can benchmark its' own HSE performance. This technical paper deals about the processes introduced by Kuwait Oil Company in with an analytical and practical approach which systematically covers to a large extent the whole range of issues involved regarding performance parameters, assessment/monitoring, controlling in the area of HSE management. Achievements made in the performance of the company, trends of all leading/lagging indicators, etc. It also summarizes with approach to be adopted by the industries in selecting right HSE measures for measuring/monitoring and controlling.

The conclusions are that while selecting and finalizing the HSE performance measures, assessment, monitoring methods, procedures and the related management aspects, it is necessary to view it objectively, and on risk-based approach. Besides, management review is an important tool ensuring Management by Objectives.
Novel Laboratory Measurement for the Characterization of Tight and Shale Formations during Transient (Unsteady State) Flow Regime
Authors: Amro Mohammed , Freese Carsten
Published: March 2015

To provide a more reliable assessment of tight and shale formations, it is essential to know their physical properties as they immensely affect the economic production of hydrocarbons from these reservoirs.

In this paper, emphasis will be laid on determining the permeability and porosity of these formations based on laboratory investigation.

To determine the permeability of tight samples, instationary test equipment has been developed and built, including the transient measurement principle. The interpretation of data using this method allows the permeability, effective porosity and Klinkenberg effect to be quantified by means of just a single measurement run. The evaluation of the measured data is carried out numerically via the inverse solution of the differential flow equations. Evaluation procedures and experienced gained in determining the permeability and porosity of various tight materials such as caprock, salt rock samples, tight gas and shale gas cores are fully addressed. In addition, the sophisticated experimental setup will be presented.

Together with the determination of the pure density of samples by helium pycnometer, reliable statements can be derived about the properties of the pore space of the material. Furthermore, the use of mercury porosimetry in determining the porosity and pore radius distribution of the tight samples is also highlighted.

The detailed analysis of the results of the porosity and permeability measurements provide valuable insight for the evaluation of the reservoir with valuable information such as dual porosity behavior.
A Practical Approach for Modeling Low Salinity Waterflooding in Carbonate Reservoirs
Authors: Althani Mohammed G. , Hoffman B. Todd
Published: March 2015

Improving oil recovery by low salinity waterflooding (LSWF) has gained a lot of attention in the last two decades. The effect of LSWF was demonstrated by coreflooding experiments in several core samples from sandstone and carbonate reservoirs around the world. Also, this effect has been shown at the field scale by some field trails.

While the exact mechanisms that cause increased recovery due to LSWF are not fully understood, most agree that changes in wettability and interfacial tension are the reasons that LSWF perform better than high salinity waterflooding (HSWF). Therefore, LSWF can be modeled by changing the property that determines the effect of wettability in fluid flow equations, which is the relative permeability. In this paper, coreflooding results from a carbonate reservoir are used to find the relation between the relative permeability curves for HSWF and LSWF. A numerical simulation model of the coreflooding experiment showed that the relative permeability for the LSWF in carbonate reservoirs can be estimated by changing only one parameter in the Corey-type relative permeability equation of the HSWF: residual oil saturation.

An application of this result was performed on a full-field simulation model to evaluate the effect of LSWF using simulation and economics. The field model was built for a carbonate reservoir in the Madison formation of Wyoming. The simulation results showed an increase in the recovery factor of more than 5% by using LSWF instead of HSWF. Furthermore, an economic analysis was performed to determine if the additional oil would justify the expense of making low salinity water. With proper assumptions of the construction and operating costs of a water desalination plant, a development plan with LSWF showed a higher net present value than a development with HSWF.

This research provides a practical approach to evaluate the effect of LSWF on certain fields using simulation. It provides a screening tool to evaluate quickly the oil gain from the LSWF before spending money on core samples testing for further research.
An Improved Drilling Simulator for Operations, Research and Training
Authors: Kelessidis Vassilios C. , Ahmed Shehab , Koulidis Alexandros
Published: March 2015

This work describes the functionalities of the drilling simulator to optimize well drilling utilizing offset data offering also training modules for novice and experienced drillers. It fully simulates the drilling process using WOB, RPM, flow, survey and lithology data and predicts ROP. It is based on Payzone simulator, introduced some years ago. The improved simulator has been tested to compare performance with drilling data from sandstone and carbonate reservoirs. The simulator has also built in functionalities like prediction of rock strength, finding optimal rheological model from viscometer data, and optimizing bit nozzle selection.

The simulator determines optimum conditions for drilling new wells utilizing offset data. It allows for fine tuning of the process. Validation is by matching predicted versus actual drilling curve. Once accomplished, a new well can be drilled, in similar environmental conditions, but with optimized drilling parameters. Training is accomplished with simple and challenging exercises, teaching students the drilling process, and allowing different drilling scenarios. It can be used for research to identify the importance of drilling parameters for drilling efficiency.

We have tested performance and predictions using literature field data and compared performance in primarily sandstone and carbonate reservoirs. Overall, the simulator is capable of simulating any formation type. Our results also show that the improved functionalities, stand-alone calculators for rock strength, rheological parameter determination and optimization of bit nozzle performance have significantly enhanced the simulator capabilities.

The results show that the simulator is very good tool for designing new wells using offset data. It provides good interactive training tool for students and engineers allowing experimentation of parameters affecting drilling process. We compared the simulator performance with respect to formation, sandstone versus carbonate reservoir and report similarities and differences.
An Evaluation of Assisted History Matching Methodologies for Giant Simulation Models
Authors: Alturki Ali , Baddourah Majdi , Pamuku Yusuf , Ravanelli Fabio , Hayder Ehtesham
Published: March 2015

Assisted history matching (AHM) methodologies provide a systematic approach to history match reservoir models accounting for uncertainties. It also provides sensitivity of reservoir response within the uncertainty range of parameters. There are usually large degrees of uncertainties in a simulation model, and as the simulation model becomes very large, both engineering and computational complexities associated with AHM methodologies become massive. The performance an AHM algorithm depends on its ability to provide a solution with an acceptable level of accuracy and uncertainty tolerance and computational efficiency to reach that goal.

This study provides performance evaluation guidelines for AHM studies and a cost benefit metrics for feasible history matching studies of giant simulation models. These metrics will take into consideration several criteria, such as the quality of the simulation model, the requirement for compute and storage resources, time to converge to an optimal or acceptable simulation model, user friendliness and ease of integration of the tool in an existing simulation environment. The goal of this evaluation metrics is to assist reservoir engineers to identify the best class of tools and algorithms, which will be appropriate for history matching studies of simulation models. The evaluation matrices were used to evaluate two stochastic tools. One is utilizing genetic/evolutionary algorithms and the other one is using different global statistical algorithms. The study is performed using an oil field in Saudi Arabia. This study identified key strengths and shortcomings of these two classes of algorithms for large scale history matching studies. The paper demonstrates that the current metrics can serve as a suitable screening tool to identify an appropriate methodology to be used in a history matching study.
An Integrated Approach to Drilling/Completion for Maximum Long-Term Productivity
Authors: Smith L.
Published: March 2015

An effective approach for enhancing production and improving hydrocarbon recovery has been to integrate production engineering with drilling strategies to design programs that optimize all aspects of well construction for optimum, long term exploitation of reserves.

This paper describes the use of such a multi-faceted approach in North Dakota Bakken wells and West Sak heavy oil sands in Alaska, both of which require long horizontal wellbores to be completed with multiple swell packers and/or liners. For maximum production, a smooth, well-conditioned, gauge hole is vitally important to enable the largest, most-effective and highest number of packers to be run.

Successfully getting liners to bottom so as to achieve optimum completions in these wells requires a repeatable process that is effective 100% of the time; therefore, requirements of both the drilling and production groups were combined in a strategy that integrates technologies specifically for improving the success of landing the liner on depth and helping drill a cost-effective, smooth, gauge hole. When these reaming while drilling techniques are used, excellent hole quality can be achieved without the need for dedicated clean out runs.

In addition to the type of packer design / reamer/ centralizers / T&D equipment utilized, the paper describes how Torque & Drag (T&D) modeling in both the drilling and liner running intervals of these wells provided a number of strategic options for achieving a useable, quality wellbore that would facilitate running liner/packers into hole without damage.

Demonstrating its effectiveness and applicability, this integrated approach has been employed on more than 100 wells to date, with more than 2 million feet of reamed hole alone, and more than 1,000 packers run on variety of wells, including runs in excess of 20,000’ and laterals exceeding 10,000’ in tri-lateral and penta-lateral wells.
Assessment of Fracture Containment and Broaching Resulting From Worst-Case-Discharge Events
Authors: Zaki K. S. , Dirkzwager J. B. , Hilarides W. K. , Connolly P. T. , Niemann J.. , Hawkins J. G.
Published: March 2015

“Worst-case discharge” is a relatively new term given to a hypothetical event that is deemed to be of low probability but of high impact. The consequences of such a discharge are substantial on drilling and completion operations for a specific well. It may also have significant implications on a fieldwide and, perhaps, companywide basis. This paper assesses, hypothetically, the circumstances that lead to such an event and the occurrence's subsequent impact on the subsurface. A hypothetical worst-case-discharge incident could be started by a kick (influx of high-pressure fluid into the wellbore during drilling). In such a hypothetical event, casing collapse could occur under the differential load (pressure within the casing is reduced significantly whereas pressure outside the casing remains high). After capping and controlling the well occur, pressure buildup occurs. Fluid could escape through the collapsed casing and migrate to surface, by means of conduits such as open annuli, unconsolidated sedimentary sequences, fractures, and salt sutures. For example, an open annulus can displace fluid to shallower horizons. Alternatively, the fluid pressure can propagate a fracture that could then broach to the surface or mudline. The paper reviews such a hypothetical event and discusses design changes targeted at mitigating and/or remediating potential negative impacts. The concept presented revolves around the positioning of casing shoes to force fracture propagation into particular horizons, thus minimizing and remediating the effects of the discharge event.