Ali Khan, Farhan (Weatherford) | Antonio Sierra, Tomas (Weatherford) | Gabriel Imbrea, Robert (Weatherford) | Robin Edwards, Michael (Weatherford) | Al-Rushoud, Ali (Kuwait Oil Company) | Al-Abdulhadi, Fahad (Kuwait Oil Company) | Shehab, Abdulaziz (Kuwait Oil Company) | Al-Ajeel, Fatemah (Kuwait Oil Company)
Project deliverables included gravel foundation preparation, concrete foundation installation, equipment reception and installation of conventional beam pumping units at 660 production wells in a remote field in Kuwait with a deadline of six months from equipment arrival. Equipment shipments schedules were sequential and therefore an execution strategy was required to successfully meet the project deadline. This paper describes the field operations strategy devised and adopted to successfully meet the deadline. A temporary operations base was set up at the remote field for coordination, equipment reception, inspection, consolidation, pre-assembly and dispatches. Operations were divided into six parallel processes as follows: 1. Equipment logistics 2. Gravel foundation preparations 3. Concrete foundation installations 4. Unit Pre-assembly 5. Pre-assembled units dispatches 6. Final unit installations Daily output targets were set for each process prior to the commencement of operations.
Bassam, Abdul-Aziz (Kuwait Oil Company) | Al-Besairi, Ghazi (Kuwait Oil Company) | Al-Dahash, Sulaiman (Kuwait Oil Company) | Sierra, Tomas (Weatherford) | Mohamed, Assem (Weatherford) | Heshmat, Kareem (Weatherford)
The demand for digital oil field solutions in artificially lifted wells is higher than ever, especially for wells producing heavy oil with high sand content and gas. A real-time supervisory control and data acquisition solution has been applied in a large-scale thermal pilot for 28 instrumented sucker rod pumping wells in North Kuwait. This paper focuses on the advantages of real-time data acquisition for identifying productionoptimization candidates, improving pump performance, and minimizing down time when using intelligent alarms and an analysis engine. Real-time surveillance provided a huge amount of information to be analyzed and discussed by well surveillance and field development teams to determine required actions based on individual well performance. Controller alarms and intelligent configurable alarms in one screen enabled early detection of unexpected/unwanted well behavior, re-investigating well potential, and taking necessary actions. The challenge was to handle heavy oil, sand, and gas production, maintain all wells at optimum running conditions before and after steam injections, and take into consideration the effect that injections would have on nearby wells. Recording in the database a "tracking item" for each well event enabled review and evaluation of the wells and creation of optimization reports. The daily, 24-hour surveillance of the wells resulted in observing common problems/issues on almost all wells and other individual issues for specific wells.
Lower Fars heavy oil <16 °API is considered a type of conventional heavy oil, which will be considered as priority petroleum production system for future heavy oil recovery in Kuwait. These types of oils are abundant in great amounts in Ratga field North Kuwait, yet expensive to produce due to its high viscosity hence low mobility underground. Kuwait strategy is shifting focus to these types of oils since conventional medium oil and other less-quantitative-light-oil reservoirs are continuously depleting. The study's interest is directed towards a specific type of EOR oil, which is hot dry air sequestration into Lower Fars heavy oil. This study presents novel heavy oil recovery method for 14 °API crude oil using hot dry air as well as their potential recoveries. All recoveries considered for this study are bench-scale laboratory physical experiments with horizontal (0 °), vertical (90 °), and directional (45 °) continuous air diffusion augmented with applied different thermal heat treatments.
The main objective for this research is to model recovery efficiency from this hot dry heat diffusion technique (HDAD). This technique will produce air diffusion design. This design will consider direction of blow diffusion for three possible well orientations: horizontal 0 degrees, vertical 90 degrees, and directional 45 degrees. Also, the design will consider six temperatures: 27 °C 30 °C 60 °C 70 °C 85 °C and 100 °C dry hot air diffusions. Moreover, the design will consider two diffusion velocities 74.08 km/hr and 111.12 km/hr. These velocities will determine designing the time of recovery, which is one hour, according to lab-time limitations and permissions. The main technology motivation for hot dry air diffusion (HDAD) research is finding the optimized economical EOR recovery efficiency factor that will extract most of 14 °API Lower Fars oil. The model determines the recovery potential factor in a classic, optimum and conventional economic scenario considering the energy usage to generate the hot dry air delivered to the reservoir. Also, HDAD technology usages will avoid the use of water technologies recoveries. Avoiding water technology recovery will minimize environmental impact, crude oil/ emulsions subsurface-mobility issues and costly water production management used at current steam economic challenges.
The South Ratqa heavy oil field, located in the Northern part of Kuwait, will be developed thermally with the first phase of the development expected to become on stream in 2019. The water source to make up steam is coming from the Municipality Sewage Plant Sulaibiya (SWWTP) located in Kuwait City. The Sulaibiya plant is handling sewage water which is locally treated to make it suitable for further use. In the treatment process, RO units are used, and the reject stream of those RO units was identified as water source for the steam plant in the South Ratqa field.
In total six steps are required to cover the full treatment scheme of the Boiler Feed Water (BFW) plant, namely: (a) Water Clarifier and sludge treatment, (b) Multimedia and Ultra filtration, (c) Ion Exchange, (d) double Reverse Osmosis, (e) Ozone and Ultra Violet treatment and (f) finally De-aerator. Currently, the plant is being constructed as part of the first phase of the South Ratqa thermal development. Control of bacteria was identified early in the design phase to be crital to ensure successful operation of the BFW plant with minimal down time. Bacteria control will be done at two locations: Upstream of the BFW plant: chemical control of bacteria growth with chlorine addition. Within the BFW plant: mechanical bacteria control using a combination of ozone addition and UV.
Upstream of the BFW plant: chemical control of bacteria growth with chlorine addition.
Within the BFW plant: mechanical bacteria control using a combination of ozone addition and UV.
Upstream of the BFW plant, chlorine will be added in the Sulaibiya plant located 123 km from the South Ratqa field. The project team realized that the added chlorine at this plant would not be enough to fully limit bacterial growth throughout the 123 km pipeline and more importantly, the growth in the 3 storage tanks upstream of the BFW plant. It was then decided to add extra chlorine injection capacity in the BFW plant just before the storage tanks. A suitable test protocol was developed to define the required extra chlorine demand resulting in a residual chlorine level between 0.5 and 2 mg/l entering the BFW plant and taking into account the extra residence times in the process.
The extra injection capacity is currently under design. With the help of this extra chlorine addition bacteria growth will be under control and the required high BFW plant availability can be achieved.
Lower Faras Heavy Oil Project in Ratqa, North Kuwait of Kuwait Oil Company is one of the Major Projects in the upstream business in the Middle East. Heavy oil production from a large field is a significant challenge and involve process, which are not common for normally well-developed onshore upstream production operations personnel. There shall be a Limited/No Flow from a heavy oil well as the viscosity is high and to ensure extraction of hydrocarbon in a most possible efficient manner, thermal operations (including the steam injection) is the best option available. This additional process and associated equipment, their associated hazards are not available in the conventional oil & gas production.
Though the option of having a horizontal well with no additional steam/heat given to the reservoir, the flow from such wells can recover hydrocarbons, however it is not feasible for a commercial production. As a result, for commercial production, the reservoir is injected with steam (either cyclic or flooding) to recover the hydrocarbons in the most economical method. The steam injection method comes with a few challenges and the crux of success in Heavy oil production is to manage these hazards.
There have been several accidents that occurred worldwide in heavy oil production and related experimental activities. The root cause of accidents is generally the lack of awareness during the operation and maintenance activeness of the workforce personnel. Different incidents from world over, from the hazard identification and the operability studies undertaken during the project, suggest the various challenges that are underlying in the heavy oil operations. The challenges had been addressed systematically and design enhancement to enhance the robustness of the systems were considered whilst developing the project.
Agawani, Waleed (Baker Hughes, a GE Company) | Al-Enezi, Dakhil R. (Kuwait Oil Company) | Pandya, Mehul (Baker Hughes, a GE Company) | Gupta, Pravind (Kuwait Oil Company) | Abdelhamid, Atef (Baker Hughes, a GE Company) | Al-Habib, Hamad (Kuwait Oil Company) | El-Touny, Shrief (Baker Hughes, a GE Company) | Ahmed, Tausif (Kuwait Oil Company)
Optimised drilling performance requires matching the right drill bit technology to an application, which can be an engineering challenge. Hybrid bits provide versatility in drill bit selection that was previously not possible with conventional drill bit technology, allowing for a broader range of applications. This paper details the results of a case study where polycrystalline diamond compact (PDC), tungsten carbide insert (TCI) and hybrid bits were tested in the same application in an attempt to improve drilling performance.
Each drill bit type has its strengths and weaknesses, and is therefore suitably matched for specific applications. Sometimes, a specific technology matches well to the application, and it is the ideal solution; however, there are many cases where the ideal drill bit type isn’t so clear. Hybrid drill bit technologies produced a new generation of bits. These bits reduce the difference between specific bit technologies, enabling them to outperform either type in demanding applications that require strengths from each technology to drill successfully.
A non-homogeneous carbonate formation that was prone to causing impact damage challenged conventional drill bit technologies. The 12.25–in. hole section was drilled vertically on a rotary bottom hole assembly (BHA). Initial trials with PDC bits showed that the bits suffered significant impact damage, preventing them from completing the section or reducing their drilling capacity so the rate of penetration (ROP) dropped below TCI performance. The TCI bits drilled relatively slowly, and although they were more durable, they also suffered impact damage.
Hybrid bits were tested on this project to leverage the benefits of each technology and improve drilling performance in this section. This hybrid technology achieved outstanding results in the South Ratqa field. In multiple deployments the hybrid drill bit doubled the ROP compared to conventional technologies. The benchmark performance reached by the hybrid drill bit was triple the ROP of conventional technology. The trial saved the operator up to 3.5 drilling days and more than 70% of the drilling cost for this section.
In 2014, number of exploratory wells were drilled and tested in Umm Niqa (UN) Field located in north Kuwait NE which approved a new discovery in Lower Fars (LF) reservoir.
LF is unconsolidated, sub –hydrostatic- sand stone reservoir with highly sour and moderate corrosive environment (H2S 8% and CO2 4%). Subsequently additional wells were drilled to evaluate the production potential of UN field. With rig on location UN wells are completed with test (Progressive Cavity Pump) PCP and tested. During the initial testing period the PCP is run at different speeds to evaluate the well productivity, water cut, and determine sand-free draw down to enable selection of suitable completion PCP for production.
Well UN-X is one of the developed wells which is perforated in LF sand in overbalanced condition using 4-1/2" (High Shot Density) HSD guns with 0.83" entrance hole diameter at 12 shoots per foot.
During initial testing with test PCP, the pump tripped due to high torque because of sand production (up to 60%). Five runs were performed to clean out the wellbore and repeated test PCP runs failed due to high sand production.
Coordination between FDHO (Field Development Heavy Oil) and Discovery Promotion Team was conducted to perform quick sand analysis to LF sands from offset sand distribution since subject well has no available sieve analysis. Based on the outcome of sieve analysis, decision was made to utilize one of the available SAS (Stand Alone Screen) designed for LF sand in another field to control sand production. It was agreed by both teams to install SAS in the subject well to mitigate the sand problem and minimize cost due to NPT (Non-Productive Time) of the rig. SAS was installed and the potential zone in UN-X could be tested successfully with tubing PCP. No sand problem was observed during testing and after testing while clean out operation there was no sand.
Well test showed an average liquid rate of 124 BFPD with 37% WC (predominantly completion brine). The well was put on production on November 2016 and producing till date without any sand problem.
This paper will include discussion on the approach used to select a sand control method for cold and heavy oil production. The results of sieve analysis was in the middle between sand screen and gravel pack but based on the team experience in sand control and the nature of heavy oil and its relatively low oil production rate, the decision was made to install SAS and that was proved to be prudent decision.
Al-Murayri, Mohammed Taha (Kuwait Oil Company) | Hassan, Abrahim Abdulgadir (Kuwait Oil Company) | Al-Mahmeed, Narjes (Kuwait Oil Company) | Suzanne, Guillaume (Beicip-Franlab) | Sanchez, Juan-Pablo (Beicip-Franlab)
This paper sheds light on the design of a one-spot surfactant-polymer (SP) flooding pilot in a reservoir with oil viscosity greater than 1000 cP using a vertical well. The results of this pilot will be important to optimize the selected chemical formulation and finalize the recommended injection sequence with the purpose of de-risking subsequent multi-well surfactant-polymer flooding deployment.
Based on systematic screening, preliminary laboratory evaluation and reservoir simulation, SP flooding was identified as a promising EOR method for the Ratqa Lower Fars (RQLF) reservoir in Kuwait. This was followed by extensive laboratory work to design a robust chemical formulation based on specific reservoir properties and operating conditions. The performance of the developed chemical formulation was validated by means of simulation. Thereafter, a one-spot EOR pilot, which is also referred to as a Single Well Chemical Tracer Test (SWCTT), was designed to assess the effectiveness of the selected chemical formulation mainly in terms of injectivity and oil desaturation.
It was envisioned that the injectivity of a lab-optimized SP formulation for the RQLF heave oil reservoir needs to be confirmed in connection with oil desaturation using a one-spot EOR pilot due to the relatively high reservoir oil viscosity and low injection pressure to maintain cap rock integrity. Assuming favourable injectivity, incremental oil recovery in a one-spot EOR pilot is represented by the difference in residual oil saturation after water flooding and after chemical (SP) flooding. However, achieving low oil saturation as a result of waterflooding in a heavy oil reservoir takes a long time and requires large water volumes that are not applicable to full-field deployment. Therefore, the objective of the one-spot EOR pilot that is discussed in this paper was adjusted to validate oil desaturation as result of polymer and surfactant injection upon confirming water injectivity within a 3ft radius of investigation as outlined below: Initial water injectivity test Polymer solution injection Measurement of oil saturation Surfactant-polymer injection followed by polymer drive Measurement of oil saturation
Initial water injectivity test
Polymer solution injection
Measurement of oil saturation
Surfactant-polymer injection followed by polymer drive
Measurement of oil saturation
This paper describes a methodical approach to de-risk surfactant-polymer flooding in a heavy oil reservoir using a one-spot EOR pilot. There is limited reference in the literature, if any, to field deployment of surfactant flooding in heavy oil reservoirs with an oil viscosity of more than 1000 cP. The findings of this study can be used to evaluate and potentially improve the techno-economic feasibility of chemical EOR in heavy oil reservoirs with similar properties.
This paper describes seismic attributes approaches and rock typing in channelized reservoirs of North Kuwait. Seismic facies with a range of frequencies from 10 - 50 Hz, along with four other attributes: semblance, RMS frequency, instantaneous phase, relative acoustic impedance and RMS amplitude of shallow upper Cretaceous channelized system are calculated and the channel infill and overbank deposits are represented in maps. Five classes are used and found to be sufficient in the unsupervised classification method. The seismic facies classification was matched against the above-mentioned four attributes and found to correspond to them. The major channel components are illustrated with the
Steam injections in shallow heavy oil targets come with a risk of breaching the thin cap shale sealing layer and not fully understanding the thickness and continuity of shale barriers within the reservoirs. This paper presents an investigation to mitigate those risks through different seismic attributes and rock typing for shallow Tertiary and Cretaceous reservoirs in North Kuwait which extended to a deeper heavy oil targets in neighboring fields. This work that studies all the key risk elements in such heavy oil reservoirs mitigates the drilling and steam injection risks of heavy oil field development. Those who utilize seismic data to map heterogeneities must realize that the changes we observe in our seismic events can be due to one of the following items: depositional environments, sweet spots, stratigraphic features, lithology, petrophysical properties such as porosity or fluid or clay content, geohazards, etc.
From a previous study presented this year at Geo 2018 for Tertiary targets, we concluded that Simultaneous geostatistical inversion (SGI) added much value in terms of delineating the shale barriers and enhancing resolution, in addition to estimating effective porosity for well releases.
The manuscript focuses on benefits realized in sucker rod pump system performance, number of workovers, downtime periods, and overall production efficiency as a result of continuous steam injection (steam flooding) on a heavy oil pilot field. It also presents benefits on production performance as a result of realtime well optimization of sucker rod pump systems. Implementation of real-time production optimization techniques to record behavioral changes provide for up-close field operational surveillance (allowing for faster response time). The steam injection effect varies from between locations, based on the distance between injector and producer wells, along with the degree of down-hole interference. The objective was to study steam injection effects on a group of wells and adjust the operational parameters of sucker rod pump systems based on individual well performance conditions. Real-time wellsite monitoring (including creating notifications, warnings and alarms to identify troublesome or non-optimized wells) and data-trend analysis allowed us to make necessary corrective actions continuously, which led to an improvement in well performance since steam injection started (thus optimizing productivity). The continuous steam injection, supported by real-time optimization and constant sucker rod pump system performance adjustments, led to the following operational efficiency improvements: 1. Reduced downtime related to troubleshooting activities 2. Reduced pump replacements (obtaining longer run life of downhole equipment) 3. Improved pump efficiency (measured by improvements in production rates) 4. Created a workflow for sucker rod pump system performance review and optimization opportunities 5. Improved field-wide overall production 6.