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.
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.
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
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.
This paper describes a combination of reservoir drilling fluid (RDF) and filter-cake breaker technology applied on four extended reach wells offshore Abu Dhabi which and provided multiple improvements in production rates of long horizontal laterals . The need for clean-up acid stimulations was reduced or eliminated in wells that could be beyond the reach of coil tubing.
The paper highlights the field implementation of these fluid systems and details the laboratory developmental work that coincided with the drilling and completion campaign. Three wells have been drilled with specialized reservoir drilling fluids (RDF) that included a premium grade xanthan, modified starch, carbonate with an internal filter cake breaker. Premium lubricants were included in the RDF to ensure that the drilling BHA could reach the ± 20,000 ft target depth and the liners could be run all the way to bottom. Acid stimulation of the nearly 10,000 ft reservoir sections was planned. The first two wells were drilled successfully, liners were run to bottom and the internal breaker was activated by a slightly acidic pH. The acid stimulation has only been performed on them to improve the initial production rate which was already near the expected target rate, while acid stimulation was not required for the third well as its performance has met the expected production rates. Subsequently, the fourth well utilized a more comprehensive cake breaker system and improved lubricant. Results of this well met production expectations also without the need for acid stimulation. Details of each well performance, field operations and results, including the laboratory development program are thoroughly discussed. Furthermore, impact of lubricants on RDF rheological properties, drilling performance and liner running torque and drag is detailed. In addition, the influence of reservoir drilling fluid design, lubricants and delay additives on the performance of the breaker is identified.
Al Braiki, Saleh (ZADCO Petroleum Co) | Al-Sawadi, Obadah Saleem (Zakum Development Co.) | Afzal, Muhammad (Zakum Development Co.) | Odeh, Nadir M.M. (ZADCO Petroleum Co) | Yar Khan, Naeem Shahid (Zakum Development Co.) | Al Hosani, Abdulla Hasan (ZADCO Petroleum Co) | Bani Malek, Ahmed (ZADCO) | Yousef, Anwar (Halliburton Co.) | Faruqi, Shamim (Halliburton)
In ZADCO's giant offshore oilfield, the Surface-Controlled Downhole Safety Valve (SC-DHSV) system of some oil producers failed to operate. Thorough investigation revealed that SC-DHSV landing nipple sealbore damage was the root cause of failure. The failed SC-DHSVs were temporarily replaced with A-3 Storm Choke Valves.
The conventional solution to restore the integrity of a failed SC-DHSV was the workover. However, efforts were made in identifying a viable rigless solution by thoroughly reviewing the available options and as an alternative, special oversized B-Type seals were chosen to substitute the existing conventional V-Type packings that failed to seal in said valves.
To ensure safe field implementation, a risk assessment was conducted followed by successful yard testing. Field implementation was successfully completed by utilizing conventional slickline unit which saved significant time and cost. A standard SC-DHSV was redressed with the oversized B-Type seals, set in the landing nipple and functioned normally. The redressed SC-DHSVs were routinely tested during the following year with no concern reported. The successful implementation was documented and is recommended for future use in similar cases.
Well integrity, Downhole Safety Valve (DHSV) System, DHSV Landing Nipple Polished Sealbore Area, Risk Assessment, Workover, Rigless Application.