Oil wells performance can be determined from completed zone productivity, completion type and size, and surface facilities. A significant surface tool, wellhead choke, can profoundly impact on the well performance. Determining the optimum choke size can result in improving the production of the well by altering the wellhead pressure, therefore the pressure drop. Increasing the bean size above optimum might result in decreasing wellhead pressure below flowline pressure and prevent the oil from flowing.
To determine the optimum choke size for oil well; live trial and error could be helpful, though it is not practical and need to be combined with a well simulation analysis and history matching. A multiphase flow simulator is applied on a set of selected wells, having bottlenecks and backpressure issues in Kuwaiti oilfields. The simulation has been developed by choosing a precise flow correlation that presents a reliable flow behavior and pressure drop results. A comparison of different flow correlations was performed against the actual test readings to eliminate a potential error from the simulation against the actual readings.
Changing the choke bean size was a quick, effective, and economical solution to overcome the bottlenecks and backpressure issues in individual candidates. Simulating the formation productivity and assessing the well performance and changing the choke size can increase the successfulness chance of the live trial and error procedure. It can also help in categorizing the wells whether to be a candidate to have choke size change, or another solution is required to flow the well such as a surface pump, artificial lift, or changing the receiving facility pressure, if possible. All the selected eighteen wells are vertical or slightly deviated with an oil API gravity between 32 and 35 degrees, and the flow behavior correlations were between the
A debottlenecking analysis is presented in this project, and supported with data matching and field test results. The procedure to optimize the choke size is explained in details using a multiphase flow simulator and an in-house developed excel sheet. Several additional approaches were analyzed to overcome backpressure issues, like using ESP artificial lift method.
Khunmek, Thanudcha (Mubadala Petroleum) | Abu-Jafar, Feras (Mubadala Petroleum) | Chigbo, Ikenna (Mubadala Petroleum) | Laoroongroj, Ajana (Mubadala Petroleum) | Mohd Ismail, Ismarullizam (Tendeka) | Parrott, Keith (Tendeka)
This paper describes a pilot program for the application of an Autonomous Inflow Control Device (AICD) by retrofitting an existing ICD completion for reservoir optimization. New drill horizontal wells were required to be completed with AICD's to enhance recovery with existing ICD completion materials in inventory desired to be used. The workflow for establishing the decision change from ICD to AICD completion and the completion design process change is discussed.
The well program was selected to demonstrate the effectiveness of AICDs in the Jasmine asset, a current field development in Thailand. ICD screens had previously been purchased for a different application but were unused. To reduce overall project cost and asset inventory, a method of utilization the existing ICD screens was strongly desired. An evaluation was done, followed by design and development of a manufacturing process to retrofit the ICD screens with larger sized AICD housing. Furthermore, overall completion design was implemented to ensure a smooth deployment and optimized production benefit.
Multiple joints of existing ICD screens were successfully retrofitted with AICD technology locally within the region. The operator was able to reduce current inventory book levels by 20% that resulted in a direct cost saving of 40% comparing to new AICD screen cost. The field deployment of the retrofit completion was a success without any operational issues.
Despite the improved productivity and uplift in reserve recovery associated with horizontal wells, reservoir heterogeneity can cause uneven production and early water and gas breakthrough from portions of the wellbore. The AICD delivers a variable flow restriction in response to the properties (viscosity) of the fluid with water or gas flow restricted. With multiple segmentation along the horizontal section in this application, excessive production of unwanted gas and water have been limited. Installed in late 2017 and another application in 2018, production from the wells have exceeded expectation, with an uplift in recovery.
The paper / presentation objective is to describe the achievement of the first gas lift well completed for multistage, hydraulically propped stimulation in a Romanian offshore field. The scope of the paper is to present the challenges and learnings associated with this well concept / design, engineering, modelling, equipment selection, yard testing, final design / program and offshore installation, operation, and results.
Reservoir depletion modelling indicated artificial lift would be required as early as 6 months within initial well start up. In order to effectively optimise production from the well for a longer range of well life cycle, a multi-stage stimulation sandface completion was selected and plans were made to install gas lift equipment during initial completion installation, prior to rig release. To meet the concept requirements, risks were assessed and case histories were investigated / incorporated during the planning phase to ensure reliability of performing high-pressure stimulations through gas lift (dummy) valves.
The material selection and specifications of the lower and upper completion equipment were defined considering: Artificial lift design Reservoir characteristics, Casing size, High pressure stimulation, Life of well operations
Artificial lift design
Reservoir characteristics, Casing size, High pressure stimulation, Life of well operations
Equipment suitability and compatibility considerations resulted in a few equipment selection changes, requiring yard trials to define optimum pulling / running tool string components and configurations, which were then applied offshore.
The final upper completion design consisted of gas lift mandrels (Gas lift dummies were replaced with gas lift valves following the HP stimulation), safety valve, permanent downhole pressure gauge and chemical injection mandrel. The lower completion consisted of hydraulic open hole packers, open hole anchor and open-close stimulation sleeves (all HP rated).
Collaboration within the multi-discipline and with multiple service providers was vital in developing the final, tested design and implementation in the offshore well. The current design in the well is showing great benefits in terms of production (a higher rate than expected) and cost (initial completion includes gas lift equipment already available for future potential use). The concept proof is considered to be of great success for upcoming projects and is increasing the confidence of the operator to develop and approach the upcoming wells with multistage stimulation gas lift completions.
This is the first well constructed in Romania that was hydraulically stimulated using proppant through an upper completion already having gas lift capability. A review of literature indicates this is an industry first. The success and communication of this well could provide benefit to the industry and could increase confidence when combining life-of-well requirements early in the well construction process.
Kosset, Talgat (K&M Technology Group) | Sissenov, Olzhas (K&M Technology Group) | Novokshenov, Stanislav (K&M Technology Group) | Niverchuk, Andrey (Schlumberger) | Golenkin, Mikhail (Lukoil-Nizhnevolzhskneft) | Zvyagin, Vasily (Lukoil-Nizhnevolzhskneft) | Nabiullin, Renat (Lukoil-Nizhnevolzhskneft) | Dadashev, Afrand (Lukoil-Nizhnevolzhskneft)
Extended-reach drilling (ERD) from a fixed offshore platform poses unique challenges for anticollision directional drilling and wellbore construction. Wells completed in multilayered reservoirs, multilaterals with compartments of varying pressure, and ERD wells are becoming common in the Russian sector of the Caspian Sea. An integrative approach and advancements in drilling and completion technologies in the Korchagina field have enabled enhanced hydrocarbon recovery through extreme reservoir contact from ERD wells.
Various issues, such as wellbore stability, borehole geometry, torque and drag, and borehole condition can affect the deployment of completion hardware to the desired depth. This paper presents the installation of ground-breaking technology in an ERD well in which the longest fully electrical intelligent completion was landed successfully through proper design and careful planning. The paper will also present the planning and execution of three ERD wells completed by use of a fully electrical intelligent completion consisting of multiple downhole active flow-control devices controlled by a single downhole electrical line. The installation of these completion systems allowed the operator to control the breakthrough of water or gas or both, to selectively produce additional hydrocarbons from multiple zones and compartments in real time, and to minimize the number of required production logging tool runs.
In 3D complex well profiles, while running the long completion string, axial drag is accumulated along the string, which exposes it to sinusoidal and helical buckling. Excessive compressional loads in the string beyond the buckling limit of the pipe can lead to lockup and ultimately prevent the string from reaching the setting depth.
This paper presents a structural integrated approach for successfully deploying a fully electrical multipoint pressure and temperature measurement completion systems on 3 ½-in. and tapered 3 ½ × 4 ½-in. tubing by using a wireless electric connect-disconnect system.
The most common practice to deploy a lower completion with inflow control devices (ICDs) requires a washpipe assembly to facilitate deployment. Due to the nature of traditional ICDs, with open flow ports, the washpipe assembly provides a conduit to circulate fluids during the installation. However, makeup and break out of washpipe takes time, carries risk, and provides no long-term benefit to the completion or long term value to the operator. The industry has used temporary mechanical isolation in more recent years, but these devices lack redundancy in the event of malfunction. The objective of the hydro-mechanical ICD is to remove the requirement for washpipe, thereby reducing operational risk and rig time while eliminating HSE concerns related to drill pipe handling when deploying the lower completion. The key differentiator being additional redundancy, should manipulation be required. An additional feature of the tool is position verification, the ICDs benefit from a passive attenae. The attenae reader can be deployed in the future to independently verify sleeve position should well optimization be required over the well lifecycle as water cut increases. The paper reviews various techniques that have been adopted to date and concludes with presenting a hydro-mechanical solution that was successfully installed and the value derived.
Objectives/Scope: A new vision with new techniques of wells' upper and lower completions have been applied successfully throughout a giant offshore multi-reservoir oilfield. Wells with long to verylong laterals have been completed successfully following a systematic strategy based applications and showed tremendous success. This paper will present the various techniques used completing wells in different reservoirs considering well-integrity and HSE regulations in order to achieve the maximum wells' deliverability's at their lowest costs throughout the well life. Many challenges were faced and overcame in order to reach the optimum completion that suits each well. A complete journey from reservoir simulation to well and network models, well performance to reservoir management studies, from geological models and interpretation to geo-science and seismic inputs, in addition to actual production data, all helped to achieve the overall target. From the phase of design to the phase of implementation and beyond to the production phase, each piece of information yielded a certain potential that led to a certain completion design based on available data and expectations. Methods, Procedures, Process: This paper will discuss the new innovative upper and lower completion designs' strategies along with the execution and performance from production engineering perspective in order to reach the maximum productivity for the life cycle from these long horizontal wells at the lowest possible cost. The extended lateral length in these wells warrants innovative designs in upper and lower completions, as the traditional completion designs no longer suite to address the challenges in these wells. The key well design and planning process involves designing the upper completion including suitable tubing size with the most effective and durable gas-lift system, and lower completion liner designs for different wells' cases.
Ramah Moorthy, Kuhaneswaren (Schlumberger) | Mohd Zainudin, Nik Mohd Mokhzani (ExxonMobil Exploration and Production Malaysia Inc) | Nor, Nazri (ExxonMobil Exploration and Production Malaysia Inc) | Arief Tham, Nabilla (ExxonMobil Exploration and Production Malaysia Inc) | Huang, Pin Y (ExxonMobil Exploration and Production Malaysia Inc) | Ishak, Eliza (ExxonMobil Exploration and Production Malaysia Inc) | Ismail, Abdul Malek (ExxonMobil Exploration and Production Malaysia Inc) | Wijoseno, Danny Aryo (Schlumberger) | Sorman, Ignatius (Schlumberger) | Yong, Nigel (Schlumberger) | Liu, Hai (Schlumberger) | Nwafor, Chidi (Schlumberger) | Ling, Kong Teng (Schlumberger) | Wibisono, Rahmat (Petronas)
Coiled tubing (CT) sand cleanout has been a normal practice for offshore wells, and repeated cleanout runs will have to be done over the years to sustain production. It has been observed that the production period of these offshore wells has shortened significantly after each cleanout due to sand particles loading up in the production tubing at a faster rate. This production trend is typical for wells with no downhole sand control in the original completion. Various aspects in terms of well design and reservoir conditions have significantly increased the complexity of sand cleanout. This, for example, includes the large 9 5/8-in. casing section with small dual upper completions of 2 7/8-in. production tubing, a high angle with a long horizontal section, and severely drawn-down reservoirs. There were also previous findings on the well where cement pebbles were found on the production choke at surface contributing to higher risk during intervention.
An integrated engineered solution was brought forward to successfully execute the CT sand cleanout job by capitalizing on both engineering and operational efficiencies. In terms of technical and engineering design, a differential-pressure-based rotating jetting tool, real-time fiber-optic downhole telemetry system, nitrified cleanout with a shear-thinning gel fluid that has superior suspension ability, and a milling tool for cement pebble cleanout were utilized. Operationally, an electrical submersible pumping (ESP) system capable of providing continuous supply of seawater and custom-built skidding beams for sand screen deployment purposes were also introduced for the first time for CT operations in southeast Asia that successfully improved operational efficiency and job safety.
A remedial sand control solution was also used to improve production longevity after sand cleanout, without doing any major pull-tubing workover or sidetrack drilling. Either through-tubing sand screens or a sand agglomeration treatment technique was carefully chosen and deployed to address the sand load-up issue in these wells. This paper discusses the operations, challenges, and the key success factors that have contributed to a well-engineered CT cleanout and deployment of sand screen and sand agglomeration treatment.
In the Arabian gulf alone, there are an estimated 500+ wellhead towers, of varying designs, varying complexity, varying cost, currently installed.. Expand that to a global view and the number is estimated to be greater than 7000.
Consider the magnitude of life cycle cost savings and HSE performance improvements that would have been made if all those towers could have been designed differently, with significantly less topsides equipment and hence CAPEX, reduced maintenance requirements resulting in much lower OPEX, offshore visitation reduced to once per year, helicopter transportation eliminated – and yet the same basic function maintained. More importantly, as our industry faces up to the challenge of increasingly marginal field developments in an increasingly cost competitive environment, consider the potential to unlock previously non-economic projects through a new approach to this key element.
In this paper we demonstrate what the wellhead tower of today could look like, based on a case study of a recent project undertaken for a major operator. We discuss the technologies required and the approach to operations and maintenance to significantly reduce the life cycle cost, reduce offshore visitation and improve the HSE performance of future wellhead towers.
Finally, with an eye to the ever-evolving future, we project how a similar approach may be adopted not only for wellhead towers, but for more functionally complex processing facilities.
For the first time in the region, a multistage fracturing completion technology that enables simultaneous fracturing and controlled sand production was successfully installed. After the fracturing operation was conducted through frac ports in multiple zones, coiled tubing (CT) intervention was needed to shift the frac ports closed and then open the production sleeves located within the sand screens. It was necessary to use the appropriate shifting tools and utilize the downhole parameters to ensure the shifting operation success.
CT was first utilized to mill the frac balls and associated seats after the fracturing operation, and this was followed by CT intervention to close the frac ports and open the sand control production sleeve. CT providing real-time downhole parameters was utilized during the shifting operation as its downhole weight provided the ability to apply required surface forces to shift the respective well accessories. Additional benefits were gained by utilizing the depth correction and obtaining the required differential pressure across the shifting tool in real-time ensuring tool functionality at optimum parameters.
The success of the innovative multistage completion operability depended on the successful implementation of shifting operations to close the frac ports and open the production sleeves with sand screens. Therefore, it was very important to select and deploy the appropriate shifting tools that can be trusted to actuate each of the respective well accessories. A series of yard tests were conducted to understand the hydraulically operated shifting tools. After the successful yard tests, during the design phase, each of the shifting operation steps were elaborated with the respective contingencies, and it was confirmed that the CT equipment utilized for the job can provide the required surface and downhole weights.
The hydraulically activated shifting tools operation during the actual CT intervention was optimized using the CT by providing real-time downhole measurements of depth correction, tension, compression and pressures. The downhole measurements helped in repeating the shifting step as needed and helped in confirming that the respective well accessory is shifted. During the intervention, two frac ports were shifted close. Whereas, there were two production sleeves with screens shifted open.
The use of the two different hydraulically activated shifting tools during the shifting operations for the first successful multistage fracturing with sand control completion system will be detailed. The paper also describes the full benefits of monitoring downhole parameters during shifting operations enabling the tools to operate at optimum conditions and ensuring the shifting is conducted successfully.
New operational application using a field-tested stimulation technology that was previously only available as a permanent installation as part of the lower completion was recently successfully applied as a retrievable option. This alternative installation method reduces rig time, overall project cost and returns the wellbore to Open Hole should it be required for post stimulation logging or future interventions. The lower completion stimulation technology consists of standard liner pipe that is made up offline to short Subs and the sub-assemblies are then preloaded with four tubes up to 40 feet in length, each tube with a jetting nozzle on the end. The liner string with casing packer was run into the open-hole well section with Subs positioned across the formation where stimulation was required. 15% HCl acid was then pumped at the designed rate that resulted in the penetration of the tubes into formation. Post stimulation the complete liner assembly was then retrieved by releasing packer with straight pull and shearing tubes that has entered the formation (the penetrated needles remain inside the formation). Many operational challenges were overcome by the PDO’s drilling team in order to complete this first of its kind installation utilizing multiple running string combinations and a small work over rig (Max 125 kdan) in order to keep the overall project cost down.