bluuebunny/crossref_metadata_2025 huggingface dataset:
Application of Comprehensive Harmless Waste Treatment Technology to Treat Drilling Cuttings in the Tian Mountain Front Block in Tarim Basin
Authors: Jinzhi Zhu , Long Li , Da Yin , Jiaxue Li , Shaojun Zhang , Yuping Yang , Jie Zhang , Yushuang Liu
Published: November 2017

Due to high temperature, high pressure, and gypsum-salt formation, the stability and rheology of conventional polymer drilling fluids are difficult to maintain, so sulfonated drilling fluids (SDF) or oil-based mud (OBM) are recommended to drill deep formations or ultra-deep formations.

However, a large number of sulfonated drilling cuttings or oily cuttings are generated in the process of drilling operation. These drilling cuttings contain a large number of harmful substances, including petroleum hydrocarbon, sulfonated additives, heavy metals, and so on, which are toxic and difficult to be biodegradable, so the discharge of drilling cuttings into environment will lead to serious contamination of soil and groundwater.

Therefore, the environmental impact of the use of SDF or OBM is one of the main challenges facing petroleum industry. One of the most difficult environmental problems to resolve at the well site is the disposal of drilling cuttings, which is often physically unstable and unsuitable for landfill.

High temperature deep pyrolysis technology (HDPT) is developed to treat sulfonated drilling cuttings from deep formations. The field results indicate that the content of petroleum hydrocarbon of treated drilling cuttings is less than 16 ppm, and various indexes of treated cuttings could meet the requirement of environmental protection. HDPT technology is characterized by high treatment efficiency and no secondary pollution, and it is very suitable for harmless treatment of sulfonated drilling cuttings.

Leaching and resource utilization technology (LRET) is currently applied to treat oily drilling cuttings from ultradeep complex formations. The results indicate that the oil content of treated drilling cuttings is less than 0.6%, and the recovery rate of OBM is over 20%. LRET technology can not only recycle and reuse OBM resources, but also guard against environmental pollution from drilling operation, and thus produce great economic and environmental benefits.

Comprehensive harmless waste treatment station for drilling cuttings is built in this Block. HDPT and LRET technology can provide a powerful technical support for achieving safety drilling in this Block, and they have been successfully applied to treat drilling cuttings from dozens of wells in this Block. This paper presents field data to illustrate the application of this comprehensive harmless waste technology and evaluate the potential technical and economic benefits that it might provide to petroleum development and production in Tarim Basin.
Use of Data Analytics to Improve Well Placement Optimization Under Uncertainty
Authors: Busby Daniel , Pivot Frédérik , Tadjer Amine
Published: November 2017

Well placement optimization is probably one of the most challenging problems the oil & gas industry has to face particularly for green fields development. The complexity of the task comes from different factors: huge number of possible solutions, increasing size of reservoir models, difficulties to correctly modeling and handling uncertainty, complex well trajectories and operational constraints, … The optimization problem for multiple wells is also extremely hard to solve due to the exponential number of possibilities to test. Although several optimization methods have been proposed in scientific and technical articles, the most used approach in industry remains the manual optimization performed by well trained reservoir engineers. The workflow proposed here aims at assisting reservoir engineers to better perform their choices on main factors affecting the optimal well placement and to be able to test much more well configurations. To this end, a machine learning algorithm is trained on simulated data to be able to evaluate the performance of new possible well locations and configurations. Differently to previous experimental design approaches, complex geological features based on expert knowledge are extracted from the geological model in order to find the main factors driving the production mechanisms. Both properties along well trajectories and properties corresponding to connected reservoir zones are used as features in the machine learning method. Clustering techniques are used to select the training data to simulate used by the machine learning algorithm. The method also handle geological uncertainty that is a critical factor in well placement optimization particularly for green fields. A large number of realistic horizontal well trajectories honoring the different operational constraints is generated, then once the machine learning method is validated a very large number of these trajectories combinations can be evaluated in seconds.

The result of the approach are illustrated in a realistic synthetic green field where the objective is to optimize the position of three wells two producers and one injector under uncertainty (corresponding to several geological realizations). A test on real field case has also been performed, but will be presented in more details in a future work. Data analytics methods allow us to evaluate millions of possible well placement configurations on many geological realizations by performing only a few thousands full field reservoir simulations. We demonstrated this could help engineers placing wells in very profitable positions minimizing risk while maximizing long term production.
Supervised Waveform Analysis to Find Wasia Carbonate Stratigraphic Traps in Rub' Al-Khali Basin, Saudi Arabia
Authors: AlQattan Hussain , Zhang Sihai
Published: November 2017

The Wasia Formation presents opportunities to explore for stratigraphic traps in the Saudi Arabian Rub’ Al-Khali Basin because it contains numerous interbedded reservoirs, sources, and sealing rocks. The mid-Cretaceous Wasia Formation includes a rudist carbonate platform with five, third-order sequences comprising, from oldest to youngest, Safaniya, Mauddud, Ahmadi, Rumaila, and Mishrif members. These members include proximal shallow-marine, highstand carbonate shoals at the platform margin in close proximity to fine-grained carbonate deposits in the Shilaf Basin. The resulting depositional cycles and stratigraphic architecture position muddy-tight seals, adjacent to porous shallow-marine carbonate-shoal bodies. Two members (Safaniya and lowermost Mishrif) have high organic-matter content situated in the oil window.

Core data, well logs, seismic signals, and modern analogs were analyzed to help understand the Wasia deposition. Detailed correlations were made of well logs and neural network training was used to generate electro-facies. Next, supervised waveform analysis was used, correlated to five well log facies, to create five waveform facies including (1) lagoon, (2) back-shoal, (3) shoal, (4) slope, and, (5) basin facies. Sources of potential uncertainties include data processing, seismic to well ties, position of stratigraphic tops and seismic horizon interpretation. To minimize these, care was taken in data processing and a blind test was performed to validate the final interpretation.

On the basis of integrating the aforementioned data with our waveform facies, a reference geological model was built demonstrating that potential stratigraphic traps are porous, shallow-marine carbonate shoals intercalated with muddy-tight slope deposits resulting in isolated, porous carbonate reservoir bodies sealed by tight rocks. For example, the Ahmadi Memberseal was deemed to be too thin to seal the oil in the underlying Mauddud. In addition, muddy-tight lowermost Mishrif Member strata are also too thin to seal oil in the underlying Rumaila. In the worst case, laterally extensive upper Mishrif reservoirs are not sealed by interbedded lateral seals even though the Aruma shale seals their tops. The two best trap configurations include (1) the first highstand lower sequence of the Mishrif reservoir sealed by interbedded extensive transgressive muddy Mishrif carbonates and (2) thick Ahmadi and lowermost Mishrif fine-grained carbonates sealing Mauddud and Rumaila highstand system tracts.
Outlast the Blast, Avert the Loss
Authors: Ajith Shenoy Manur , Adel Khalid , Al Awadhi Ibrahim
Published: November 2017

Buildings that are manned and/or housing critical equipment are ideally conceived to be sited at safe distance away from potential explosion sources of the gas processing facilities. However it is not always possible to maintain the required stand-off distance due to several layout/operational constraints in brownfield projects and hence plant buildings are invariably subjected to the blast effects. The paper discusses challenges confronted and best practices followed in GASCO for blast protection of plant buildings.

Quantitative Risk Assessment study forms the basis for blast considerations on the building, wherein potential Vapor Cloud Explosion scenarios are identified and blast overpressure are quantified in the form of contours on the plot. Buildings located within the blast contours and are manned/housing critical equipments are classified as blast-resistant to ensure safety to occupants and facilitate safe shutdown of process units during explosion. Building performance requirement defining acceptable level of damage is determined based on criticality of the facility/expected occupancy (control room, FAR, etc.). Structural system/material appropriate to blast intensity is chosen and a dynamic or equivalent static analysis is performed.

Blast resistant design followed for buildings in GASCO plants incorporates a practical approach blending past experiences with best known practices in the industry. Building Blast Design Requirements (BDR) data sheet is introduced at early stages of the project and specific requirements such as blast load parameters, building configuration, structural system & foundation type, building response range and other special requirements are developed and firmed up before the commencement of detailed design.

Single-storied regular shaped buildings with no windows or minimum windows with special features are preferred. Elevated ground floor is permitted in certain cases such as Substation to create cable vault. However this presents unique challenges in establishing blast pressure distribution due to lack of guidelines for such set-up, which is overcome by own novel solutions.

For low blast loads, simplified static approach is adopted for structural analysis, while dynamic analysis with SDOF approach yields economical design for medium to high blast loads. In specific cases where SDOF idealization is inappropriate (as in multi storied building), a MDOF non-linear FE analysis is carried out.

RC framed structure with reinforced masonry walls, or steel structure is adequate for low blast, while RC shear wall structure is found most effective to sustain moderate to high blast.

The paper presents best practices and unique approach followed in GASCO for such design amid growing challenges of achieving high performance at low cost. These requirements are common for similar expansion projects and hence can be adopted across the industry.
Effective Use of Reservoir Surveillance to Optimize Production in a Complex Stacked-Sand Oil Field
Authors: Laoroongroj A. , Last N. , Ali A. Bu
Published: November 2017

This paper discusses how surveillance data are collected and integrated to assess the effectiveness and optimize the management of an offshore waterflood, and describes how an enhanced understanding of well performance, flow behaviour and reservoir architecture is used to optimize production and injection.

A comprehensive reservoir surveillance plan is essential in order to understand reservoir behaviour and to optimize ultimate recovery. Multiple surveillance techniques are used including pressure build up and fall off tests, production logs, cased hole formation resistivity and saturation logs, and wireline formation pressure measurements which provide critical information on reservoir connectivity in wells drilled after production start-up. Voidage replacement ratio (VRR) is carefully tracked in each reservoir unit. Hydrogeochemical modelling is used to understand the water chemistry interaction between injected water and formation water, and diagnostic methods such as Hall plots are used to assess injection well performance before and after well stimulation.

Several challenges have arisen since the first wells were put on production. Two of the most significant have been, firstly, to maintain water injection for voidage replacement and, secondly, to understand the reasons behind unexpectedly early water breakthrough at the producing wells. Two case studies illustrate how information from well surveillance has guided the response to these challenges.
Characterization of Fault Damage Zones and Associated Fracture Networks and Their Influence on Fluid Flow in the Tight Carbonate Reservoir
Authors: Shen Feng , Torres Marcos , Mosqueda Francisco , Gutierrez Jose Carmen , Guevara Fernando , Wu Shengyu
Published: November 2017

In the tight carbonate reservoir located in onshore Mexico, fault damage zones and associated fracture networks represent major permeability structure and greatly affect fluid flow. In this study, we present a method for characterizing and modeling fault damage zones and fracture networks. The main objectives are to use fault damage zone and fracture network models to predict fluid-flow pathways in the reservoir and to understand their impact on well production performance.

Appropriate geometric attributes are used for unsupervised seismic facies classification with the aim of delineating fault damage zones. The utility of the facies approach lies in its capacity for classifying the fault system with distinct classes based on the degree of fracturing. The three-dimensional fault damage zones are extracted and modeled from the seismic facies volume. A natural fracture network model in the target formation is deterministically built by meshing fracture lineaments that are automatically tracked along depth slices of the edge-enhanced curvature attribute. The fracture network model provides fracture characters in terms of fracture orientation, length, density and connectivity. Local fracture network models at individual wells can be built using fracture connectivity analysis technique.

The fault damage zone model delineates fault zone architecture and spatial variability. Our results show that the main fracture sets parallel or subparallel to the fault zone strikes regionally. Fractures distribute surrounding fault damage zones with enhanced fracture density. A good correlation between the fault damage zones and the lost circulation is observed. Based on the production data, fault damage zones can act as fluid conduits. In some instances, fault damage zones can create flow barriers. Conditioned with well data, the conductivity of the fault damage zones and related local fracture networks is calibrated. Using the local fracture network model, the fluid flow pathways and fracture vertical connectivity are determined. With borehole breakouts and drilling induced fractures, the identified maximum horizontal stress orientation is in the NNE direction. Our results show that the conductive properties of fault damage zones and fractures could be affected by the stress state and in situ stress orientations. This explains the fact that the wells located in the fault damage zones and fractures with the orientations preferable for extension tendency or slip tendency have high productivity.

The continuous fault damage zone model and the discrete fracture network model can be used to capture 3-D complexity of fluid flow in fault damage zones, improve the prediction of flow pathways and help the lateral or horizontal well design.
First Unconventional Onshore Proppant Fracturing Treatment in UAE – Not an Easy One
Authors: Pooniwala Shahvir A. , Franquet Javier A. , Onafowokan Adebayo O. , Erickson Daniel R.
Published: November 2017

UAE which has traditionally been an oil producing country is reassessing the nation's energy production strategy and are appraising alternate energy sources. A part of this strategy includes exploring and assessing the potential of their unconventional and tight gas reservoirs. In order produce gas at economic rates from these deep unconventional reservoirs hydraulic fracturing is a vital technology to unlock the reservoir potential and enable hydrocarbon flow to surface.

The first onshore hydraulic fracturing treatment in UAE was a challenging operation since the target formation was never successfully fractured previously. The expected breakdown pressure, insitu stresses and pore pressure regimes were unknown. A robust workflow was put into place using global and regional experience. An integrated formation evaluation was conducted during drilling and logging the vertical wellbore in order to select target zones and perforating intervals. Triaxial testing and ultrasonic measurements were conducted on core samples from the treatment well to calibrate the Geomechanical model before the hydraulic fracture treatment execution. Detailed lab testing was carried out to assist fracturing fluid and proppant selection. Multiple hydraulic fracturing simulations were conducted to define the final stimulation treatment program.

Evaluation of the target UAE unconventional gas reservoir during the drilling and evaluation phase indicated the formation possessed high static stiffness, highly laminated depositional environment, significant overpressure and high insitu horizontal stresses. These formation characteristics posed some challenges during the hydraulic fracturing design and execution. High fracturing treatment pressures and propellant based perforation charges were required to effectively breakdown the formation in order to place the proppant into the fracture during execution. The stimulated target zone showed good initial gas production post treatment execution, which met the primary objective of proving recoverable gas in place.

The hydraulic fracturing lessons learned from this first onshore unconventional well will be applied to future exploration and appraisal wells to ensure stimulation success and hydrocarbon deliverability. Unlocking the large quantity of gas from these organic rich carbonate reservoirs will play a significant role in UAE hydrocarbon production strategy.
Future for Ancient Sulphur Recovery Units SRUs at Habshan
Authors: Hassan Yasser , AlRaeesi Fatima
Published: November 2017

Taking into consideration ADNOC's strategic areas on performance, profitability, efficiency and people, one of GASCO's focus is to optimize and improve the efficiency of the existing equipment, particularly to those of more than 20 years in operation. Among these equipment are two trains of 3-stage Claus Sulphur Recovery Units in Habshan-0 Plant, considered to be the oldest, in which a study was conducted to explore different possible upgrading options.

Units-50 and 51 are two units among eight other SRUs in Habshan Complex. These units are a 3-stage Claus SRUs in Habshan-0 Plant having a maximum recovery efficiency of around 97% and are a major source of excessive SO2 emissions.

A study was carried out to identify the units' requirement and to upgrade the recovery level to a minimum of 99.0% for future use. The study identified the required modifications (equipment, piping, instrumentation, etc.) and its impact on the existing equipment and facilities for the options considered: (1) Conversion of the third catalytic Claus stage in each SRU train to a Selective Oxidation Stage (2) Addition of a new Selective Oxidation Stage in each SRU and (3) Addition of a new Selective Oxidation Stage common for both SRU-50 & 51.

The three options were studied for revamping of SRUs-50 & 51 from Claus to SuperClaus. Several factors were considered in studying each option such as the plot space available in Habshan-0, operating capacity, complexity with respect to safeguarding and maintenance, utilities requirements inside SRU, additional equipment, required CAPEX, etc.

Due to a high CAPEX requirement, option 3 was not further evaluated and considered to be non- feasible. Options-1 and 2 were further evaluated; detailed investigation of option-1 resulted in a lower expected Sulphur Recovery Efficiency (SRE) in comparison with that of option 2, consequently it was withdrawn as it does not meet GASCO's requirement for a minimum 99.0% SRE.

Option-2 (Addition of a new Selective Oxidation Stage in each SRU) on the other hand provided the expected SRE of 99.15% (guarantee is 99.0%) Start of Run (SOR) / 98.94% (guarantee is 98.9.0%) End of Run (EOR) hence proved to be the best techno-economical feasible solution for upgrading the SRUs.
Heavy Oil Production Challenges and Solutions in North Kuwait Pilot Project Illustrated through Case Examples
Authors: Al-Marta Abduallah , Al-Basheer Yousef , Al-Mehri Mohamed , Al-Metlea Mubarak , Sierra Tomas , Ibrahim Assem M. , Fawzy Mohamed H. , Sobhy Mustafa S.
Published: November 2017

Heavy oil production is becoming standard for the industry as demand continues to increase. The first pilot, in the South Ratqa area of North Kuwait, experienced challenges related to producing such low API production in 6 heavy oil production facilities. The manuscript will focus on the challenges faced during initial set up, solutions executed during the trial phase, and the preventive measures taken to assure smooth daily operations and production of heavy oil.

Well surveillance, field development, and field operations teams met to agree on the operation structure and the daily resources, equipment, and facility requirements to run the field. Full time surveillance resulted in a complete picture of well performance and allowed a deeper understanding of the challenges in this unique formation. The main challenges were low API production, sand production, different gas production rates, the remote location, and thermal production issues that occurred after steaming.

Sand production is a major challenge to producing as it affects pump performance and flowline and production facility operation. Producing such low API oil, especially in harsh winter temperatures, resulted in plugging the flowline and made oil shipment more difficult. In order to handle high gas production rates, relieving and flaring systems were installed. This solution positively affected the down-hole pump performance and production facility tanks. Deploying the pilot in a remote area of Kuwait resulted in delayed support, equipment, diesel, water, and power supplies required for daily operations.

Using steam as an enhanced oil recovery method resulted in solving most of the above challenges while increasing oil productivity. Based on the challenges faced, data collected, researches executed and different solutionsapplied, the objective of the pilot to understand the reservoir behavior and operational requirements have been fulfilled.

This successful pilot is the main reference for heavy oil applications and field development in Kuwait. It is the first project applied to increasing production in the South Ratqa field. After the pilot's success, an additional 28 wells were successfully deployed. Another project, with over 1,000 sucker rod pump wells, has been planned for the same field.
A New Cost Effective and Reliable Water Shutoff System: Case Study in Kuwait
Authors: Al-Ebrahim Ahmed E. , Al-Houti Naser , Al-Othman Moahmmad , Hamad Al-Mehanna , Al-Mehanna Mohammad , Mubarak Abdullah , Al-Adwani Yousef , Mahmoud Wael , Hai Liu , Panga Mohan , Lafitte Valerie , Lee Jesse
Published: November 2017

Increased water cut represents one of the biggest challenges to the oil industry, with more than 75% of the produced fluid being water that brings an increased cost per barrel of oil through water handling, scale deposition, corrosion, and mainly the bypassed oil reserve.

Water shut off solutions range from mechanical solutions like bridge plugs to chemical treatments that include cement, resins and polymer gels. Cement applied as a plug or a squeeze treatment is often the preferred option to the operating company for isolating unwanted production intervals near the wellbore, and crosslinked polymer systems are also commonly used when deeper penetration is required. However, the success of these treatments often suffers from mixed fluid quality, zonal isolation (cementing quality), proper placement, numerous downhole conditions and more importantly backflow of unset cement slurry or immature gels while cleaning up leftover slurries in the wellbore or pulling out the work string after the treatment. In this paper, a new system based on a single nano-additive is described to shut off a water zone in a South Kuwait regional oil producer. The new system, which does not require curing but acts rapidly in porous media, addresses the concern of backflow associated with unset cement or crosslinked polymer fluids.

The objective of this treatment was to seal off the upper zone that produces mostly water, reduce overall water cut from 90% to less than 10%, and test the productivity of the lower zone. The well configuration does not allow zonal isolation without a rig, so cement and other known chemical treatments were unsuitable for this application.

Eighteen barrels of the water shut-off treatment was pumped through coiled tubing (CT) and injected into a 34 ft zone resulting in nearly immediate response through increased wellhead pressure. The injection was resumed every three to four hours to ensure a complete sealing of the target interval. The fluid starts workingupon injection into porous media but always remains as liquid phase when kept in the wellbore or surface tanks, so there is no concern about sticking or plugging the coil. The operational time was reduced compared to normal water shut off jobs, and the single additive fluid is low viscosity making surface mixing simple.

The novelty of this water shut-off system is efficient sealing of a high permeability formation with minimal fluid and achieving a drastic water cut from 90% to1%. This new system, unlike polymer-based systems, doesn't degrade with temperature, water hardness or salinity, and plugging of the porous media works by acompletely different mechanism leading to a more robust barrier against water production with reduced interventional risk.
New Insights on Coiled Tubing Acid Tunneling Stimulation in Carbonate Reservoirs
Authors: Livescu Silviu , Craig Steven
Published: November 2017

A coiled tubing (CT) acid tunneling stimulation technique has been successfully applied in the last 15 years on limestone and dolomite reservoirs around the world (Middle East, South East Asia, North America, South America, and Europe). Several case histories were presented in the past showing that this technique brings significant benefits over other carbonate stimulation methods in open-hole wells. In this paper, the parameters influencing the predicted and achieved tunnel lengths are discussed.

The acid tunneling technique consists of pumping hydrochloric (HCl) acid through conventional CT and a bottom-hole assembly (BHA) with jetting nozzles to create (without drilling) stable drainage holes (tunnels) out into the reservoir pay zone. The BHA also includes a special kick off tool with two pressure-activated bending joints that controls the tunnel initiation direction. The acid that is not consumed during the main tunneling process leaks into the reservoir rock creating wormholes that improve the connectivity between the reservoir and the wellbore and positively impact well production. This acid tunneling technique can create as many tunnels as required at different depths. The optimization of the tunnel initiation depth selection is made by production software simulation using such critical information as the well parameters (trajectory, size, etc.) available logs (image, resistivity, caliper, drilling), past reservoir information, etc.

The CT acid tunneling technique on carbonate wells has yielded excellent results when compared to conventional acid jetting with CT, matrix acidizing and acid fracturing. Many case histories from regions around the world were presented before (Stanley et al. 2010). However, many questions are unanswered about what actually happens downhole in terms of tunnel initiation and creation. Most importantly, a detailed discussion regarding the acid tunneling modeling software is included. The parameters influencing the predicted tunnel lengths and the parameters that could be monitored or adjusted in order to protect the CT from any damage and to smoothly create the tunnels are discussed.

The paper describes the CT acid tunneling technology and discusses some of the most important questions regarding the downhole CT acid tunneling. The acid tunneling technique performance and benefits confirmed during the recent field operations are presented.
Crevice Corrosion Effect on Alloy 625 in Untreated Seawater Environment
Authors: Al-Abbadi Sara , Aoudi Hiba , AlShouly Wael , Saeed Waled , AlSafatli Khalifa , Toubar Ashraf
Published: November 2017

The main objective of this paper is to present the impact of crevice corrosion not only on ordinary metals but also on highly Corrosion Resistance Alloys. The paper highlights the failure of Inconel 625 in sea water service at an elevated temperature, in addition to the recommendation for alternative metals for such service conditions.

In order to examine the influence of temperature on crevice corrosion specifically for Alloy 625 (UNS N06625) in highly chlorinated environment such as untreated seawater, an intensive study was conducted with consideration of service corrosively, material composition, operating conditions, etc. The main driver of this study was the sever crevice corrosion pitting founded at PTFE, Polytetrafluoroethylene, coated Inconel gasket seating area. The failure occurred at the inlet gas coolers containing hydrocarbons in the shell side, and sea water on the tube side for one of the new offshore facilities. The incident resulted in a leakage of the sea water at flange joints for both ends of the channel and shell side. Although Inconel 625 is the world class Corrosion Resistant Alloy (CRA) which offers superior protection from corrosion and eliminates the need for expensive maintenance and repairs, it repeatedly failed to serve as expected.

The outcome of the investigation showed a direct relationship between the potential of crevice corrosion and service temperature in the system where Alloy 625 is being used. The study results showed that crevice corrosion can aggressively attack the surfaces of Alloy 625 when the service temperature exceeds 40°C.

As an action and a way forward to resolve this problem, a higher Molybdenum (Mo) containing alloy shall be utilized for flange face repairs and for the gaskets, accordingly Alloy 686 "Hastalloy" is the recommended alloy for this application. Unlike Inconel 625 CCT, Hastalloy is known for its excellent resistance to crevice corrosion and its Critical Crevice Temperature up to 85°C.
Application of a Fuzzy Expert System to Analyze and Anticipate ESP Failure Modes
Authors: Grassian David , Bahatem Mohammed , Scott Trevor , Olsen Daniel
Published: November 2017

Electrical submersible pumps (ESPs) are employed in a growing number of oil and gas developments. A high level of availability of the ESPs is essential to production assurance. The purpose of this research was to develop a basic ESP fuzzy expert system and to demonstrate its application. An ESP Fuzzy Expert system can provide a consistent means to analyze ESP operational data. The analysis can be used to either predict developing failure modes or to retroactively determine the causes of a prior failures. The main steps involved in the development of the ESP fuzzy expert system are as follows: identify input variables, develop membership functions, develop rule sets and develop output functions.

Input variables representing slopes were mapped to membership functions denoted by linguistic terms such as "increasing", "constant", and "decreasing". The input variables are also assigned a member value to indicate the Degree of Fulfilment (DOF) of the individual premise. The Degrees of Fulfilment (DOF) of all the premises are then combined to determine the overall DOF of the rules (Adesanwo et al. 2016), with each rule representing a distinct failure mode.

To validate the system, operational data from an offshore oil and gas field located in the Gulf of Thailand was collected and analyzed using the prototype ESP Fuzzy Expert System. This dataset consisted of nine ESP systems selected from a pool of more than 100 ESPs installed in the field. The nine ESP systems were composed of four ESP pumps which were running smoothly and five ESP systems that eventually failed. For the failed ESPs the operational data leading up to the failure was analyzed. Trends were analyzed for periods of 7 days, 30 days and 60 days for each ESP system.
Meeting ADNOC CoP CO & SO2 Emission Limits, at What Cost? Case Study
Authors: Nagwani Dheeraj , Hassan Yasser
Published: November 2017

Objective / Scope

Over the past several decades, ADNOC has adopted increasingly strict clean air regulations. ADNOC Code of Practice (CoP) stipulates that the Sulphur dioxide (SO2) and carbon monoxide (CO) emissions limits from Sulphur Recovery Units (SRU) (categorized as material producing industry) is restricted to 2000 mg/Nm3 (700 ppmv) and 500 mg/Nm3 (400 ppmv) respectively.

GASCO Habshan plant existing SRUs are not designed to meet the current ADNOC CoP emissions requirements.

This paper explores all possible options for SO2 and CO emission reduction from Habshan complex SRUs along with cost associated with each option.

Methods/Procedure

Habshan Complex SRU's Licensors (B&V and Jacobs) and an independent third party consultant were approached to identify the all possible options for SO2 and CO emission reduction.

Results, Observations and Conclusions

Sulphur Recovery Efficiency (SRE) of above 99.5% is required to achieve SO2 emission of 2000 mg/Nm3 (700 ppmv). This can be achieved only by installation of either Amine based TGTU or Caustic Scrubbing Unit. Estimated Capital Cost for installation of such units is approx. US$ 230 MM for all the SRU's in Habshan i.e. U-52/53/54/57/58/59/152/153 (except U-50/51). Also, as sulphur recovery efficiency increases, the energy required to remove each additional kilogram of sulphur escalates. As energy consumption increases, so too do CO2 emissions, which is an undesirable outcome.

Similarly, CO emission levels can be achieved by 1) Operating the incinerator at higher temperature or 2) by Installation of hydrogenation reactor upstream of incinerator for tail gas treatment or 3) by Incinerator modification/replacement.

Operating Incinerator at higher temperature will lead to increase in fuel gas consumption and consequently increased CO2 release from stack. Estimated increase in operating cost for incinerator operation at Higher Temperature is approx. US$ 3 MM/yr (at current capacity).

Installation of Hydrogenation rector will incur significant capital cost. Estimated Capital Cost for installation of hydrogenation reactor is approx. US$ 45 MM for all the SRU's in Habshan i.e. U-52/53/54/57/58/59/152/153 (except U-50/51).

Incinerator modification / replacement will cost approx. US$ 4-5 MM for each incinerator.

While endeavoring for lower SO2 and CO emissions may be beneficial from environmental point of view, it does not come free of cost. In fact, it comes with substantial increase in cost.

This paper explores all possible options for SO2 and CO emission reduction from Habshan complex SRUs along with cost associated with each option. It also investigates energy consumption and associated CO2 footprint with each option.
Integrity of LNG Flare Systems
Authors: Sabry Houssam
Published: November 2017

ADGAS is a leading LNG producer. It is the pioneer LNG supplier in the region. LNG trains are operated since 1977. Through those years of experience, ADGAS has been following a stringent Asset Integrity Management System for all its plants. Among these plants are the flare and relief systems. Flare systems are considered safety critical. Maintaining the integrity of these systems is a challenge. This paper shares ADGAS best practices in maintaining the asset integrity of these plants. The paper also highlights the latest development in the area of flare systems inspection and shares same case histories.

The world of Asset Integrity Management has advanced over the few decades to a great deal. Inspection has progressed from being time based to condition based then to being Risk Based. ADGAS Asset Integrity Management has passed through all these developments. For instance inspection of flare systems and plants was first time based. Then based on the performance of some of its plant systems it became condition based. Afterwards more optimization was added and it became Risk based. Technology has also advanced across the years, for instance, flare tips replacement was a strictly time based program. Then became condition based, then now we can inspect the flare tips systems online using special Unmanned Aerial vehicles (UAV's). This enabled ADGAS to truly optimize on maintenance and replacements of the flare tips. These examples will be shared in the paper. Furthermore at few instances failure of some flare systems provided great experience to avoid recurrence, flashback case, flare piping systems ageing and repair are all cases that are to be shared in the presentation.

Utilization of latest inspection technology, latest repair technology and monitoring enabled ADGAS to optimise its inspection and maintenance costs. The last savings on flare systems maintenance were estimated at a value of USD MM 3.5. Some old flow control measures were proven to possible create problems, for example restriction orifices to control the flow of purge gas can get blocked if not maintained. Restriction orifices can be changed for other means of control to avoid possible restriction of purge gas flow which is essential for the integrity of flare systems.

Latest UAV inspection technology has added towards the inspection and maintenance of flare systems. Utilization of more advanced monitoring and flow control of flare purge gases is of high importance. Usage of novel techniques in piping repair represented an important aspect in optimizing the maintenance cost of flare systems.
Foam Cement Implementation - Deepwater Angola Case Histories
Authors: Joao Antonio T. , Andrade Gerson , Alegria Adriana
Published: November 2017

Cementing the 20" surface casing in offshore Angola is associated with low fracture gradients and shallow water flows. These particular challenges require the use of lightweight slurry with both bead materials, and tight fluid loss control which was the initial approach for the section mentioned above. Due to high slurry volumes, rig site bulk logistics deployment, and budget, Foam cement was proposed. The Paper describes the design methodology and implementation of an automated foam cement system with real time monitoring. Based on the challenges presented above, Foam cement slurry has been the choice for some operators in Angola. Using a constant N2 injection rate with a foaming agent and a stabilizer that are injected into the slurry prior to it reaching the foaming "T" with variable choke bean size where N2 is injected into the slurry prior to pump downhole. Specific developed software’s, and Local training classes with in class and field training have proven to be very efficient allowing to have flawless execution pre and post job comparison and data evaluation.

The foamset cement system has shown to be very reliable and efficient on covering shallow surface areas likely to preserve fresh water aquifers. A standard slurry design was developed; thickening time adjusted depending on well conditions. The slurry was stable both at surface and downhole conditions with foam quality varying from 20% to 35%, providing required compressive strength. Since the implementation in Angola, 26 jobs have been performed successfully. This slurry can undergo a wide range of downhole pressures and temperatures variations without deforming the cement in place and or compromising well integrity.

This paper will share experience and success acquired in offshore Angola with best practices used in laboratory testing, both operations and engineering planning, execution, and post job data results.
Integrated Water Injection Treatment System Optimization and Impact on Field Injectivity on a Giant Offshore Carbonate Field. Case Study
Authors: Sarsekov Arlen , McNeilly Kevin , Al Neaimi Ahmed , Saif Omar Yousef , Salimov Rail
Published: November 2017

Water Injection is a part of secondary recovery to sustain Reservoir pressure and improve sweep efficiency and consequently improve recovery factor of the field with minimum cost. Source of the water is varying between offshore and onshore fields.

Normally for all offshore fields, water injection source is sea water. However, it is vital to have proper water injection treatment system to avoid the risk of issues at surface and subsurface levels.

This case study will show how water injection treatment system is important and their impact on the decrease of water injection efficiency due to plugging and corrosion. In addition, it will show the proper mitigation plan for improvement of water quality for short/mid and long term planning of the field development.

Injected sea water should be treated mainly from the following parameters: –Sand solids from the sea using the sand filters–Oxygen removal from corrosion–Bacteria’s–Chemical inhibitors.

Each of these parameters was checked and improved on the field and successful results were observed in terms of pipeline conditions and injection sustainability.

Due to the poor water quality, every year 15-20 water injectors were plugged or decreased dramatically due to water quality. Improving the quality of the water and setting the proper guidelines for the treatment standards showed a positive impact on injection sustainability and consequently improved production offtake from the field.

The holistic approach of the water injection treatment system and mitigation plan become possible uses the right standards of the treatment and correct surface facility. This will help to sustain water injection rate and decrease the number of acid jobs performed due to a decrease of the performance. Solving the cause of the problem is crucial instead of acting on the consequences.
Multi-Zone Completion Design Optimization in Offshore Prolific Carbonate Reservoirs: A Systematic Approach
Authors: Hernandez Eglier Yanez , Okotie Victoria , Malouf Christophe Bassem , Al Sereidi Amnah , Zidan Maher , Abdel-Karim Islam , Abdul-Halim Abdulla Adam
Published: November 2017

Completion design is a key factor in maximizing well inflow performance and deliverability throughout the life of a well. During the early stages of development of a green oil field located offshore Abu Dhabi, improved subsurface understanding from data gathering led to the modification of the initial completion design. This paper presents a systematic approach utilizing an integrated workflow to successfully optimize multi-zone horizontal well completions to lower development costs, reduce risks and increased field recovery. The final well architecture was implemented in the Early Production Scheme (EPS) and Full Field Development (FFD) phases of the development. The main achievements of the integrated completions design are: ○Increased well productivity and deliverability.○Optimized completion strategy for low efficient gas lift wells.○Reduced risks in well construction and completion phases.○Improved completion flexibility for life-of-well intervention operations.○Optimized slot allocation to increase recovery with more wells.○Utilized full benefits of conductor sharing technology.○Added flexibility to successfully appraise an undeveloped carbonate reservoir and to incorporate it into the development plan.○Adopted new methodology for lower completion design in multilayer reservoirs.○Considered simultaneous dual system injection and production (SIP) wells.

The comprehensive approach presented is valuable in establishing a total life-cycle workflow during the early stage of field development, which can be embedded in any completion design strategy. The completion solutions highlight significant benefits from overcoming well-known challenges in offshore environment such as space limitations, slot availability, and cost optimization. The end product is a life-cycle design identified for each specific reservoir with reduced operational constraints and well intervention complexity.
Granulated Sulphur; Design & Operation Optimizations
Authors: Al Suwaidi Eman Thani
Published: November 2017

ADNOC has one of the largest Sulphur Granulation and Handling systems in the region designed for 22000 MTPD with a common main receiving/export facilities at Ruwais and two granulations facilities at Habshan and Shah fields that were commissioned in 2014.

The sulphur is produced as a side product from the Gas Processing in particular from the Gas Sweetening Process that removes H2S then is converted to Liquid sulphur in the Sulphur Recovery Units (SRU) and finally that liquid sulphur is processed to produce Granulated Sulphur. In general, the higher the gas sourness (High H2S content) the higher the sulphur production.

Production of large amount of granulated sulphur with the existing design had its impact on generating Sulphur Dust that raises HSE and integrity concenrs. Nevertheless the large scale sulphur granulation production and the sulphur dust issues did not stop ADNOC to produce a premium level granulated sulphur quality, that mainly follows SUDIC-Sulphur Development Institute of Canada-Specifications, where this product is being exported to different international markets since the commissioning of the plants couple years ago.

The credit of ADNOC success goes to overcoming different challenges faced throughout the plants life cycle starting from the project (Study and execution levels), to commissioning and starting the normal operation and maintenance level up to date.

This paper will introduce number of challenges in vels, design level and the operating level that stimulate sulphur dust generation in all the sites, .for which the current available challenges with the way of mitigation will be addressed along with addressing the different options that can be considered in future project.

Such possible options available for enhancements in the current Sulphur Granulation and Handling Plants are listed below:–Drop height Reduction–Train Load-out Methodology–Dust Control System – Dust Suppression – by spraying surfactant Versus Dust Prevention System – by using foaming.

Moreover, there are number of future different options that can be considered in the earlier stages of the project such as the study and the design stages, like: gramatic structure!!!–The transportation methodology such us using the road tracks to transfer the liquid sulphur or transferring the granulated sulphur from the granulations plants to export location via train. why?–For Granulated Sulphur the Storage mechanism of Stacking and Reclaiming selection between Booming or Pushing Stacking is significant in supporting maintaining the quality of the granulated Sulphur.

The above challenges were handled to reduce its impact on producing the Sulphur Dust that is caused by the breakage of the granulated Sulphur. And the future options proposed above are things to be studied well before concluding and finalizing the selected options or/and methodology and the sections below will highlight the above challenges and future options in much details.