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A Cathodic Protection system can provide effective corrosion control against external corrosion threats to aboveground storage tanks; be it related to tank construction materials, coating degradation over operational life span or environmental corrosion caused by tank foundation, soil etc. Traditionally, several different types of anode installation schemes were practiced for current distribution to the tank bottom. These were'Horizontal or vertical' anode installation distributed around the tank periphery or angular drilled anode installation to extend the anodes toward center of the tank bottom. Deep-well anode systems with multiple anodes in a single long bore-hole at relatively remote location were also used to provide common cathodic protection system for multiple tanks in tank farm area. These conventional anode-beds were easy to install, monitor and maintained. For safety and environmental reasons in new storage tank construction, an impermeable plastic membrane is now required to be laid under the tank to contain any corrosion leak if it happens. The use of a membrane beneath the tank bottom as secondary containment and as a means of leak detection thwarts any attempt of conventional anode-bed outside the tank periphery to be effective. The anode-bed and references electrodes or other monitoring systems are therefore installed within the space available between the membrane and the tank bottom during construction of the tank, as retrofitting of anodes during operational service life would not work because of the inaccessibility below the tank bottom. A robust design of the cathodic protection system for a tank bottom is therefore imperative to ensure intended design life. This paper briefly discusses the changing perspectives of the cathodic protection system from conventional anode-beds to a grid system showing the detail design approach adopted and highlights the implications of miss-design based on a practical example of a newly constructed 100 meter dia crude oil storage tank with 40 years design life if relevant design considerations are not addressed.
Ghorbani, N. (Tomson Technologies) | Yan, C. (Tomson Technologies) | Guraieb, P. (Tomson Technologies) | Tomson, R. C. (Tomson Technologies) | Abdallah, D. (Abu Dhabi Co For Onshore Petroleum Operations Ltd) | Aouda, A. Ben (ZADCO Petroleum Co) | Odeh, N. M. (ZADCO Petroleum Co) | Al Daghar, T. A. (ZADCO Petroleum Co)
Inorganic scale precipitation and deposition in oil and gas wells can cause significant production loss, which results in additional operational expenditure (OPEX) and health safety and environmental (HSE) risks. Scale management requires a detailed understanding of production rates, hydrocarbon and produced water compositions as well as reservoir conditions. Accurate real-time analysis of produced water compositions can immediately identifiy scaling risks in a production well and can lead to significantly reduced production loss, optimized chemical dosages, and fewer workovers, consequently lowering OPEX and mitigating HSE risk. This paper introduces development of a device capable of measuring the most critical parameters associated with inorganic scale in flowing produced water including pH, alkalinity, strontium, barium, sulfate, total hardness, total dissolve solids (TDS) and others.
In order to measure these water properties with the device, different methods were tested, but eventually, a combination of spectrophotometric and other methods were determined effective. One of the challenges of using spectrophotometric methods is the reagent stability over time. Hence, customized reagents were prepared for this application and the stability of these reagents was tested over time. Specific calibration methods were designed in order to extend the usage of the reagents.
Static measurements were initially performed and the results showed precise measurements of all the parameters. Results from dynamic tests utilizing real time flow and static test were in agreement and the accuracy was confirmed by traditional methods. Once the device prototype was built in our laboratories, production fluids were used to test the complete device. This device can be placed at various attachment points from the wellhead to the separator. This automated device is capable of collecting a discrete production fluid sample, separating produced water from the bulk phase and measuring various properties of produced water. These properties are reported electronically and used as part of a combined real time scale risk prevention system. In addition, this device measures parameters while maintaining wellhead pressure and temperature in order to eliminate the potentials errors in measurements, for instance pH of water changes due to degassing and precipitation as a result of changes in pressure and temperature.
A field trial is planned to test the device under full flowing conditions. This will be the first automated real-time produced water composition monitoring device with high measurement accuracy while maintaining pressure and temperature of samples, which can be attached at various points from wellhead to separator. This can be beneficial to identify the scaling risk in production wells before severe scaling occurs. The device is designed to enhance reliability of water properties measurements, provide real-time measurements, and reduce downtime and costs associated with scale problems and sampling.
Ryan, James (ZADCO Petroleum Co) | Grini, Morten (ZADCO Petroleum Co) | Al Junaibi, Hamad (ZADCO Petroleum Co) | Al Katheeri, Yousef (ZADCO Petroleum Co) | Edwards, Henry Ewart (ZADCO Petroleum Co) | Day, Tim (Schlumberger) | Chandran, Kumaran (Schlumberger) | Espeland, Kent (Tercel Oilfield) | Rachi, Hakim (Schlumberger)
The island development strategy of the giant offshore oilfield requires the use of extended reach drilling (ERD) design wells. Compared to the typical wells drilled from the wellhead towers in the same field, higher inclinations are required in both the surface hole and intermediate hole to facilitate drilling three dimensional wells of more than 35,000 ft. While the challenges of drilling the intermediate hole at higher angles had been identified early on due to field experience, the challenges leading to stuck pipe events encountered in the surface hole were not anticipated due to limited experience drilling high angle surface holes in the region.
Historically total loss of returns has been a common issue in the region when drilling the surface hole. Typically when drilling from the Jack Ups, the wells are drilled with sea water and high viscosity sweeps once total losses has been encountered. Any potential aquifer flows are diverted overboard. In order to divert the aquifer flows on the newly built Artificial Islands, the fluids must be pumped 200 or more meters to the gulf. Mud cap drilling (drilling with seawater down the drill string with heavy mud in the annulus to control well flows) was implemented to solve the issue of losses and flows on the island.
The early wells with surface holes drilled at high angle experienced stuck pipe while tripping out of the hole after reaching casing point, leading to significant non-productive time (NPT) and risking project objectives and planned designs. A detailed investigation was performed, including running six arm caliper logs to better understand the mechanism for stuck pipe events. After analyzing and understanding the issue, operational practices and bottom hole assembly designs have been changed to reduce the stuck pipe risk, and specially designed stabilizers have been manufactured and used to mitigate stuck pipe events. Geologically, significant data gathering within the overburden sequence to characterize lithological, stratigraphic, and diagenetic heterogeneities, as well as structural discontinuities, has improved understanding of aspect ratio and vertical scale of features being drilled that may have caused the previous hole morphology effects. No stuck pipe events have been experienced to date in the surface hole due to the same effects after implementation of the new equipment designs and improved drilling practices.
In recent years more and more construction projects used information technology applications to support execution and management tasks. However, construction companies in the world and accordingly in UAE still wrestle with information technology applications in construction (ITC) and how they could be effectively applied on their specific projects. One main reason for this struggle is that an account about how ITC have been used in the past or could be used in the future is missing. This research aims to provide new impetus to UAE’s growth and competitiveness in construction engineering and management areas.
The paper presents some areas that ITC could be applied in oil & gas construction sector of UAE. It offers practitioners such an account of the application areas of ITC technologies including the purposes for which these technologies have been applied. The paper qualitatively aggregates the results of more than 200 papers to show how ITC have been applied to address different projects challenges. The paper presents samples of key practical areas for simulation modelling applications in construction industry that are proposed by author for oil & gas projects. The main finding of this analysis is that ITC could play significant role in controlling key indicators of oil & gas construction projects performance including, but not limited to, schedule, cost, safety, quality, team work, and scope management. It could help project managers solving critical concerns such as claim analysis, cash-flow optimization, resources optimization, camp management, and many others.
Keyword: Oil & Gas, construction, UAE, information technology, project performance, ITC
Description: This presentation focusses on the development of ZADCO Performance Standards (PS) and Written Scheme of Examination (WSE) for HSE-CES (Critical Equipment & Systems).It includes the initial identification of HSECES through the Control of Major Accident Hazards (COMAH) Hazid and Envid processes which delivers a comprehensive Facility specific Hazard & Effects Register (H&ER). This H&ER forms an essential input during the development of the Performance Standards.The presentation concludes with a demonstration of the practical PS output, which is the Verification of HSECES by an Independent Competent Person (ICP) to ensure that they are adequate and will function on demand.This is achieved through an ICP Verification Audit which involves a comprehensive Examination of the HSE-CES (Critical Equipment & Systems) equipment.The ICP audit includes physical witnessing of the HSECES to ensure that the Inspection, Functional Testing & Maintenance is conducted as specified, and to ensure they function as required, on demand, to control, mitigate and/or prevent major accident hazards. Application: Similar Oil & Gas Companies (Exploration & Production) may learn from the experience in developing a detailed set of "Facility specific" Performance Standards, Written Scheme of Examination and associated HSECES Management System, as this approach includes the important aspect of being a practical, applicable, and complete system through the adoption of a comprehensive HSE-CES Safeguarding System & Equipment'Verification Scheme'.Following this presentation, Companies may adopt or reference certain aspects of the approach and develop their own approach to develop and implementation a "tailored" Performance Standards Management System. Results, Observations & Conclusions: Even at an early stage of the HSECES Management System development the results have been tangible, i.e. we have reviewed and interpreted the ADNOC (Regulatory Body) Code of Practice on Integrity Assurance (CoP 6.01) requirements into a practical working PS system to satisfy the CoP requirements.This is achieved through identification of the Major Accident Hazards and related HSECES, assigning Equipment Criticality and developing the related Facility specific Performance Standards, to ensure that sufficient Inspection, Maintenance and Testing is carried out to specified Preventive Maintenance Standards which are witnessed (on a "sample" basis) by an Independent Competent Person (ICP) Team through On-site Verification audit to ensure compliance.This process has 2 SPE-171776-MS
Elgizawy, Mahmoud (Schlumberger) | Grini, Morten (ZADCO Petroleum Co) | Al Junaibi, Hamad (ZADCO Petroleum Co) | Rachi, Hakim (Schlumberger) | Chandran, Kumaran (Schlumberger) | Adewumi, Femi (Schlumberger) | Day, Tim (Schlumberger) | Batu, Ali (Schlumberger)
Accurate wellbore geometric placement is fundamental to achieve the objective of maximizing hydrocarbon production and recovery. It is especially essential in real time to drill complex 3D well trajectories that penetrate multiple thin geological targets. Accurate placement is also critical to avoid catastrophic subsurface collision of nearby offset wells. This is critical in particular in this gigantic field with over 800 wells drilled by two different operators with several hundreds more wells to follow.
Almost all Bottom Hole Assemblies (BHA) run in this field include a Measurement-While-Drilling (MWD) survey tool to survey the wellbore while drilling. The MWD is a magnetic survey tool that is subject to errors that limit the magnetic survey accuracy. One of the main sources of error is the variation in the local magnetic field due to the crustal anomalies in this field. The magnetic surveys can provide an accurate geometric well placement by incorporating the knowledge of the local magnetic field disturbance to the main geomagnetic field model and by compensating for the drill-string magnetic interference.
The Geomagnetic Referencing Service (GRS) technique based on magnetic surveys was introduced in this field. This technique utilizes the local magnetic data that is measured over the field by acquiring a high-definition airborne gravity and magnetic survey. The accuracy of the geometric well trajectory of the first oil producer well is compared between the MWD, cased gyroscopic and GRS surveys and the advantage of the GRS is presented.
The benefits of applying GRS in real-time while drilling is paramount, where it provides an accurate well position in real time when corrections to the well trajectory are still possible. It prevents the costly sidetracks if the post drilling gyroscopic survey shows the well has missed its target. In most cases, GRS is an alternative to the gyroscopic surveys where it provides magnetic survey accuracy that is comparable to the casing gyroscopic survey tools. Hence, it saves the cost and risk of running gyroscopic survey tool as well as the cost of the extra rig time required to run a gyroscopic tool after drilling.
This giant offshore oilfield is located approximately 80 km North-East off the coast of Abu Dhabi in United Arab of Emirates as shown in Figure 1. The project development strategy was to develop artificial islands for drilling and completion purposes. Four islands have been constructed to significantly reduce the operating cost and minimize corrosion associated with offshore well heads. World class complex 3-D ERD wells of more than 35,000 ft are planned to meet reservoir requirements and close proximity with existing and future wells. To maximize production, four artificial islands were constructed with more than 1000 slots to drill ERD wells with Maximum Reservoir Contact (MRC) laterals larger than 10,000 ft.
There are approximately 800 wells already drilled in this field by two different operators. The field is getting congested and collision risk is very high. This requires high accuracy surveying technology and stringent QA-QC of the process to minimize the collision risk and safely drill the wells without any safety, production or financial implications.
Pallapothu, Surya Kiran (Schlumberger) | Bogaerts, Martijn (Schlumberger Technical Services Inc) | De Bruijn, Gunnar Gerard (Schlumberger) | Peyle, Sebastien (Schlumberger) | Rashid, Faisal (ZADCO Petroleum Co)
Cement placement plays an important role in the primary cementing process. There are several best practices in place which are believed to have significant impact on the quality of the overall cement job. Previous investigations suggest that a combination of multiple placement techniques, such as density and rheology gradient coupled with proper displacement rates, pipe rotation or reciprocation, conditioning of drilling fluid prior to cement job, pipe centralization, and bottom plugs, improves the chances of a successful cement job. However, there is little quantitative analysis available to demonstrate the importance of each technique independently in the field.
In the past 15 years, operations in offshore Atlantic Canada have cemented 140-mm and 178-mm liners in 216-mm openhole sections in two different reservoirs. The cementing designs for the liners are similar, especially in terms of flow rate, centralization (type or placement), and spacer train, but differ in pipe rotation, mud conditioning, and bottom plugs. Once the cementation process is executed, it is evaluated by an ultrasonic imaging tool, which measures the acoustic impedance to calculate the cement bond index. The average of the cement bond index for the entire liner is then used to quantify the quality of the cement job for each well.
The average cement bond index obtained from 53 wells was used to evaluate various cement placement techniques. The average cement bond index is proportional to the amount of cement bonded to the pipe and is inferred to be proportional to factors related to mud removal and cement placement. Factors that affect mud removal, such as mud conditioning, annular velocity, pipe movement, wellbore characteristics, and the presence of a bottom plug, are investigated. Statistical analysis of the cement bond index indicates that some of these cement placement techniques affect mud removal significantly more than others. A comprehensive analysis of these results and an assessment of potential benefits are presented in this study. The results of the study were used to improve the cement job design.
Over the years, several best practices or cement placement techniques have been developed for primary cementing, supported by computational simulations and have been validated through laboratory testing and large scale experiments or field tests. These cement placement techniques include displacement rates, pipe movement, pipe centralization, condition of drilling fluid, spacer design, and cement slurry design itself. There are also several published field studies that present results before and after applying the best practices. The literature always recommends following all best practices for primary cementing; however, all of them can not be followed in most cases due to operational concerns. This leaves a question unanswered: Which placement technique exerts the most influence on job results? There are numerous computational fluid dynamic simulations available to the oil industry which can simulate the different placement techniques, but comparative field data are scarce. In an attempt to evaluate different placement techniques, the authors assessed them by comparing the average cement bond index for 53 cemented liners from an offshore platform in Atlantic Canada. The offshore platform accessed two different reservoirs through extended-reach drilling over the past 15 years. The production casing comprises a 178-mm or a 140-mm liner that is set in a 216-mm open hole. An evaluation of this liner section is the focus of this study.
Depending upon reservoir type, the total vertical depth (TVD) of all the extended-reach wells ranges from 2600 m to 4000 m, and the measured depth is as much as 11,000 m. The drilled wells are typically S-shaped, and all 216-mm liner sections discussed are deviated holes with inclinations of 15° to 40°. The length of the liner sections varies from 600 m to 2200 m. The bottomhole static temperature for the liner sections ranges from 80°C to 120°C. Synthetic-based mud is used in all the wells, with a density of 1300 to 1450 kg/m3 in most of the liner sections.
Fullmer, Shawn M (ExxonMobil Upstream Research Co.) | Guidry, Sean A (Exxonmobil Upstream Research Company) | Gournay, Jonas (Exxonmobil Upstream Research Company) | Bowlin, Emily (Exxonmobil Upstream Research Company) | Ottinger, Gary (Zakum Dev Co. (ZADCO) U.A.E.) | Al Neyadi, Abdulla Mohammed (ZADCO Petroleum Co) | Gupta, Gaurav (Exxonmobil Upstream Research Company) | Gao, Bo (Exxonmobil Upstream Research Company) | Edwards, Ewart (Zakum Development Co.)
Microporosity is very common in limestone reservoirs globally and is especially significant in many large Mesozoic reservoirs in the Middle East. Despite its common occurrence there is:
1) Wide variation in its definition,
2) Uncertainty around characterization, genetic controls, and distribution
3) A rudimentary understanding of its influence on reservoir performance and hydrocarbon recovery.
The results of this study, based on a global survey of microporosity and specific Middle Eastern case studies, provide clarity on each of these topics.
One volumetrically significant type of microporosity occurs between micron size subhedral crystals of low magnesium calcite in matrix and within grains. This micro-pore system is very homogenous in terms of pore size distribution with 90% of pores between 1 and 3 microns in diameter. Pore throat radii range between 0.1 and 1.5 microns. Porosity, permeability, and capillarity relationships reflect this homogeneity for rocks dominated by microporosity. Rocks with less than approximately 80% microporosity exhibit a marked increase in pore system heterogeneity.
A pore geometry characterization approach incorporating digital image analyses of petrographic thin-sections was developed and provides a very effective means of rapidly characterizing and quantifying the total pore system, including microporosity.
The lateral and stratigraphic distribution of microporosity is systematically related to the distribution of depositional facies and the regional extent of burial diagenetic processes. Factors that inhibit burial diagenesis, such as hydrocarbon charge, also have a strong influence on the nature and distribution of microporosity.
Remaining oil saturation in microporous limestone, as measured from centrifuge capillary pressure and steady state (SS) core flood experiments, is negatively correlated with the percent fraction of microporosity. Due to the homogenous nature of the micro-pore system, rocks dominated by microporosity have more favorable oil recovery than rocks with mixed pore systems. In the specific cases studied here, water provides more favorable recovery than gas. These results have implications for resource assessment, field development planning and optimization of ultimate recovery in limestone reservoirs with significant microporosity.
A new generation geologic model for a giant Middle East carbonate reservoir was constructed and history matched with the objectives of creating a model suitable for full field prediction and sector level drill well planning. Several key performance drivers were recognized as important factors in the history match; 1) unique carbonate fluid displacement; 2) data validation and horizontal well trajectory issues; and 3) distribution of high permeability streaks. Ultimately a full field history match consisting of more than 1000 well strings and several decades of history was achieved using detailed distribution of the high permeability streaks, while honoring measured core poro-perm relationships, lab-validated displacement curves, and well test data.
This paper discusses the role of the geometry and the vertical distribution of the high-permeability streaks in the history matching of a giant offshore carbonate reservoir. Specifically, the modeling of the high-permeability streaks - which consist of thin rudist and algal rudstone, floatstone, and peloidal grainstone, with abundant, well-connected inter-particle porosity - became possible after extensive revamping of the reservoir rock type model, updating well descriptions, and a detailed zonal mapping of the high permeability streaks and dolomitic zones. The areal and vertical model resolution was doubled over the previous models to accommodate the internal sub-layering of the upper four reservoir zones in order to capture the thin (~1.4 ft) high-permeability streaks.
During the history match, local modifications of the high-permeability streaks were the integral part of the feedback loop between the simulation engineers and geoscientists that kept the common-scale simulation model and geologic model synchronized. The final history match was validated by extensive analysis of the models' vertical conformance as compared to production logs. This approach made it possible to construct a more heterogeneous model than previous models; while honoring both field KH and matrix poro-permeability without local permeability multipliers. The combination of these features provides a higher confidence model of long term well injectivity/productivity.
The subject reservoir is a giant offshore carbonate reservoir deposited in an extensive, low to moderate energy, low-angle ramp setting that stack into an overall shallowing-upward carbonate depositional sequence. It is overall mud-dominated from the base of the reservoir to the middle zone and becomes grain-dominated from the upper portion to the top of the reservoir. Major reservoir rocks include: mud-dominated (mudstone and wackestone), packstone, grainstone, algal-dominated floatstone, rudist-dominated floatstone, dolomite, and a thin generic "high-permeability streaks?? in ascending reservoir quality.
The reservoir was operated under primary depletion for over a decade before being converted to a pattern waterflood and then eventually to a line drive as its current depletion plan. Recent field development activity necessitated constructing and history matching a new generation model using the lessons from the previous model and emphasis on understanding and capturing the injected water movement including vertical conformance. It includes the latest seismic interpretation, a revamped reservoir rock typing model (Al Ameri 2011), updated well descriptions, and a detailed mapping of the high permeability streaks and dolomitic zones (cf. Yamamoto 2011).
The UAE field has many thin multilayered carbonate reservoirs. Production from thse thin reservoirs are primarily supported by water injection. Reservoir properties, such as permeability, pore pressure, and water saturation, vary significantly both across the field geographically and within the different layers.
Recently a study has been done to drill and maximize reservoir contact via ERD wells. To reduce costs and improve recovery, further development of the plan is to use wells drilled with throws greater than 15,000 ft and measured depths greater than 20,000 ft with some wells exceeding 35,000 ft. Long horizontals provide many benefits including enhanced access to offshore reserves, optimized productivity, reduced capital expenditure, and a minimized environmental impact
With these benefits come challenges, accessibility for intervention operations being the most prevalent. Many factors affect the accessibility and intervention capabilities in ERD wells. Completion ID restrictions play a critical role in the equipment availability and selection. Once equipment is selected the leading principles used for improved access in ERD applications are:
Ø Increasing pipe bending stiffness to postpone helical buckling
Ø Reducing Normal Force between the CT wellbore
Ø Reducing Friction Coefficient
Ø Adding Axial Forces
ERD applications and accessibility for interventions have been an ongoing challenge on how to properly model and predict the reach of CT in varying environments. The two pilot wells covered in this paper allowed for an array of information to be collected as the trajectories were very similar but the wells themselves were very unique. One well was a producer while the other was an injector. One well was completed with 13% Chromium and the other with conventional tubing.
In this paper we will cover the above topics in more detail to clearly outline the challenges of ERD operations and the methods to overcome them. It will be clearly outline how these methods were used on two ERD pilot wells in UAE with the supporting actual operational data. These wells and lessons learned will pave the way for future ERD operations planned in both offshore and island based offshore UAE pilot projects.