After an operator confirmed wellbore integrity failure in a well located on a small platform, a coiled tubing (CT) catenary intervention was urgently required. However, the production facilities of the platform were not authorized to operate, which represented an impediment to receive returns from the wellbore. This paper documents the analysis and implementation of nonconventional flowback methods and the actions taken to perform the intervention using a state-of-the-art fly-by-wire CT catenary package in a setup that had never used before in this field.
After a shut-in period, the subject well faced integrity issues that could end in an uncontrolled situation. To remediate this situation, milling and plug-setting runs were designed using a catenary system with a fly-by-wire CT unit set for first time completely on the vessel and leaving only the injector head on the platform. To address the flowback limitation, technical and economical assessments were performed on three options: using slope barges to receive fluids in storage tanks, setting conventional flowback equipment on board the catenary vessel, or using the gas injection pipeline available on the platform.
After analyzing each alternative, the options to use slope barges and flowback equipment on the vessel were discarded after confirming that they represented an additional risk and generated higher costs for their implementation. The use of the gas injection pipeline involved the modification of many resources on land and at the offshore facilities, and a detailed plan was needed to utilize the lines in a different way from their initial design. Additionally, weather conditions played a major role during the job execution. Consequently, a special focus was placed on elaborating contingency plans to address emergencies during the operation taking into account that the method implied handling hydrocarbons at surface under uncommon situations. The coordination and collaboration in the operation enabled the operator to achieve the expected results, recovering the wellbore integrity in a cost-effective way, while also eliminating the exposure of additional vessels or sophisticated equipment on location.
The paper presents the large amount of information that was amassed during the implementation of the solution, which could be used by other locations facing similar conditions where conventional production facilities cannot be used during well interventions. The document also includes contingency plans for every stage of the project, safety measurements, lessons learned, and details of the modifications done to the gas injection system and the CT equipment.
Gangway equipped: offshore support vessels, intervention vessels, construction vessels, and other monohull vessels, capable of providing gangway access to offshore facilities in exposed sea areas has great potential. It is playing an evolving important role in making new marginal yield field development economical, reducing exposure to risk, and extending the life of the existing oil and gas infrastructure. Otherwise known as Walk to Work (W2W), this marine manning approach for offshore facilities can be used on a regular, fixed term, ad-hoc or exceptional circumstance basis. It is capable of providing significant benefits over existing provisions including: improved safety, increased workforce productivity, greater manning flexibility, and reduced lifecycle costs. The W2W vessel can range from relatively small, fast workboats, to large semi-submersible'flotels' stationed alongside fixed platforms. Within this range, it is the mono-hull vessel where there is the greatest opportunity for the oil and gas industry to realise significant (currently unexploited) gain. Depending on the capability of the chosen vessel, a W2W solution may offer: gangway transfers, hotel, hospital, helicopter, rescue and recovery, subsea and splash zone inspection, cargo, crane, fabrication and other facilities.
A hydrocarbon logistics for transmission and distribution involves several facilities that are part of a complex process and associated functions for every single element. In comparison with pipelines, stations and terminals are generally confined to a specific site. Facilities modeling to assess risk and reliability are limited to what occurs within a fence. It is clear stations and terminals have not been subject to the same type of scrutiny as pipelines, however, this is changing and more engineering efforts are required.
Facilities components are covered in several engineering standards, where in many cases every element is considered individually without referring to every possible combination or arrangement – in other words, the user has to assemble a process from different sources. This paper provides a documented process to assemble this jigsaw in a simple way to convince operators and field engineers to use it as a supporting tool. These facilities may have one or more main parallel and support processes and a function, therefore defining a simple way for modeling becomes an important issue. It is important to bear in mind that stations and terminals may have one or more main processes, functions, auxiliary or support processes. Therefore it is important to make as simple as possible the connection between all components and a flow chart. This avoids assumptions by the analyst who has to model what it is actually seeing to obtain results that benefit its decisions.
Models to assess facilities must be based on a consistent hierarchy to establish boundaries between all possible layers in such a way that they can be evaluated independently to include their contribution in risk and reliability. This model is supported by ISO 14224 Petroleum, petrochemical and natural gas industries – Collection and Exchange of Reliability and Data maintenance for Equipment, which is devised for any user of a model’s results: industry, business category, installation, unit, section, equipment, subunit and maintainable items.
The production of oil and gas, and the various processes required to make these products suitable for transportation, is an energy-intensive operation. Provision of electrical power, process heat and mechanical power usually requires the combustion of fossil fuels with resultant CO2 emissions to atmosphere. Flaring of hydrocarbon-based waste gases also creates additional CO2 emissions at production facilities.
In many instances, taking a more global approach to facility design can greatly improve energy efficiency and hence reduce CO2 emissions. Employing Cogeneration technologies to generate both power and heat, or to recover waste heat from processes to generate electricity, can both reduce site emissions and help ensure security of electricity supply. It may also be possible to use waste-gas streams as a fuel for a Cogeneration plant, reducing the amount of premium fuel required and simultaneously eliminating gas flaring, or to sell any surplus electricity generated, turning a waste into a potential revenue stream.
There are numerous ways to configure a Cogeneration plant, depending on the ratio between the power and the heat required by the facility, the available fuels or waste heat sources, the form of process heat required and the actual electrical power demand. This paper will examine some of the different well-proven potential Cogeneration configurations based on Gas Turbines, Steam Turbines and Gas Engines, as well as looking at how the newer technologies of Organic Rankine Cycles and Concentrated Solar Power can be employed in Cogeneration applications.
With potential overall fuel efficiencies in excess of 75%, Cogeneration can offer significant CO2 reduction over separate generation of power and heat, from either an on-site or off-site facility, or imported power from a remote third-party power plant. The paper will discuss potential CO2 savings for certain common plant configurations and fuels.
CO2 can be an effective EOR agent and is the dominant anthropogenic greenhouse gas driving global warming. Capturing CO2 from industrial sources in EOR projects can maximize hydrocarbon recovery and help provide a possible bridge to a lower carbon emissions future, by adding value through EOR production and field life extension, and providing long term secure storage post-EOR operations.
Shell is working to implement new generation CO2 projects, including offshore applications. Based on recent offshore project design experience, this paper describes the challenges in moving CO2 EOR from onshore to offshore and the solutions developed, in the key areas of safety, facilities, wells, subsurface and piloting. The overriding design principle in any project is HSE. Offshore operations brings a new set of challenges over inventory, pressure, confined spaces and evacuation, with conventional emergency procedures requiring modification because of the different physical characteristics of CO2 releases compared to hydrocarbon gas. Surface facilities need to be simple to minimise CAPEX, weight and space while maintaining flexibility, since there is less scope to incrementally evolve the surface facilities as is the case onshore. Balancing the tension between these objectives requires very close surface and subsurface integration to find optimal and cost-effective solutions.
This is illustrated with three key decision areas: gas treatment options for back produced CO2 and hydrocarbon gas, artificial lift and facilities capacity.
A novel integrated CO2 gas lift system is described. This simplifies facilities and reduces CAPEX and OPEX, while at the same time providing a high degree of flexibility and risk management over the EOR life cycle in terms of subsurface uncertainty and reducing the issues around molecular weight variation in the recycled gas and the degree of turndown required in the facilities in the early years of EOR operations.
CO2 is the dominant anthropogenic greenhouse gas that is believed to be driving global warming and climate change. Carbon capture and storage (CCS) is a technology that may contribute to reduction in CO2 emissions. However, CO2 capture from flue gas sources with current technology is CAPEX and energy intensive, so that the cost of CO2 abatement with CCS is high.
At the same time CO2 is an effective miscible flooding agent for EOR. Capturing CO2 from industrial sources for use in EOR projects can maximize hydrocarbon recovery and help provide a possible bridge to a lower carbon emissions future. Firstly, by adding value through additional oil recovery and field life extension, which can offset part of the cost of CO2 capture, and secondly, by providing long term secure storage after EOR operations have been completed.
Moving from onshore to offshore
Existing CO2 EOR projects are all onshore, with the majority of projects supplied with CO2 from natural subsurface sources. A minority of projects is based on captured CO2 from anthropogenic sources, with the largest being the Weyburn CO2 EOR and storage project, using CO2 captured from a coal gasification plant . Operating offshore CO2 injection has so far been restricted to storage of CO2 produced from gas processing plants, with the Sleipner  and Snøhvit  projects each injecting around one million tpa of CO2. Maximising value from disposal of CO2, (whether this is from low cost sources such as gas processing plants or more expensive flue gas capture) requires suitable EOR target fields, and in regions such as Europe and the Far East, large scale operations require moving CO2 EOR offshore into the major hydrocarbon basins.
Suliman, Abdalla Elhaj (WNPOC) | Bin Ngah, Ab Wahab (WNPOC) | Basbar, Ashraf Elfadil (White Nile Petroleum Co.) | Anua, Nor Aidil (Petronas Carigali Sdn Bhd) | Hashim, Salaheldin Tawfig (White Nile Petroleum Operation Company)
Many of Sudan's large oil fields suffer from low recovery factors and decline in primary production due to low oil gravity (<22 API) and viscosities above 100 cP. Many wells experienced premature water production. As such, Enhanced Oil Recovery project seems to be the option to improve oil recovery in Sudan.
Thar Jath field contains in excess of 1.2 billion STOIIP, 75% of the STOIIP comprises 20° API oil with 120-160 cP viscosity while the remaining STOIIP comprises 16° API with viscosity > 680 cP viscosity. The Full Field Review which was carried out through 2009 recognized that primary and secondary recovery could only recover, at best, 9.0% of the STOIIP with infill drilling. As such, a considerable number of Enhanced Oil Recovery (EOR) techniques have been assessed in order to recommend suitable EOR development project for the field, and to position the field as leading the way in Sudan. In the absence of a miscible gas option, dynamic reservoir simulation schemes were developed for the natural depletion, water flood, chemical, thermal and immiscible gas methods.
The three most promising techniques; ASP, steam flood/CSS and in-situ combustion were developed to optimize pattern spacing, injection rates and pressures for each technique. Thereafter, facilities schemes and notional costs were developed so that economic viability could be assessed to select the most preferred technique going forward. EOR has been found to be economically and technically feasible with highest economic recovery across all reservoirs from Steam technique. There is scope for thermal recovery to take recovery factor above 40% overall. The pilot test design study is on going with the objective to proof the concept and confirm scope of recovery from steam flooding prior to full field implementation.
EMEPMI and PETRONAS have recently concluded major simulation studies on the application of immiscible Water Alternating Gas (WAG) injection to enhance oil recovery for Tapis and Guntong fields, the two largest waterflooded fields operated by ExxonMobil in Malaysia. Both fields have been under waterflood operation for more than 25 years with about 40% original-oil-in-place (OOIP) recovered to-date.
Evaluations of immiscible WAG injection process application at Tapis and Guntong fields were carried out using full-field reservoir simulation models. The scope of the evaluation work included: a) assessment of additional recovery from enhancing waterflood operations, b) assessment of recovery uplift from WAG injection, c) WAG pattern and WAG ratio optimization, d) optimal WAG operating parameters and reservoir management strategy, and e) integrating production and injection well operating conditions with facilities process design.
The Tapis WAG evaluation study has supported ExxonMobil's plans to implement a WAG project at Tapis. The study has matured to the point of providing the subsurface design basis for the Project. The Guntong study has provided an initial assessment of WAG potential used for the conceptual WAG development and
early project planning.
Du, Kuifu (Shell) | Chai, Chon Fui (Sarawak Shell Berhad) | Lo, Sho-wei (Shell) | Jamaludin, Maisarah (Petronas) | Ritom, Simon (Sarawak Shell Berhad) | Agarwal, Binayak (Shell Technology India) | Din, Azmi (Petronas Carigali Sdn Bhd) | Zakaria, Nur Atiqah (Petronas) | Azizan, Norlia (Petronas Carigali Sdn Bhd)
This paper presents a systematic evaluation of enhanced oil recovery (EOR) potentials for St Joseph Field located in the offshore Malaysia. The field has been in production for 30 years, currently under gas injection and started injecting water in March 2011. Chemical EOR (cEOR) was identified as the most effective EOR process for maximizing ultimate recovery for St Joseph and the two nearby fields. This paper presents the key results of the St Joseph chemical EOR feasibility evaluation.
It also discusses an integrated area development concept exploiting the synergies between the three fields of North Sabah, which is recognized as key to a successful cEOR development in the area.
This study aimed to understand the size of prize in case of both polymer flood and Alkaline-Surfactant-Polymer (ASP) EOR scenarios using 3D full field models. One dimensional box and single well models were used to understand the physics of the EOR processes whereas the full field model was used to investigate the EOR subsurface development concepts, infill opportunities, injector/producer placements, slug size etc. It is anticipated that the proposed ASP flood will increase the ultimate recovery factor for the EOR targeted sands to circa 65%. Potential subsurface risks/uncertainties were also investigated.
The chemical EOR process will involve handling a large volume of chemicals. This represents a major challenge in application of chemical EOR technologies in an offshore environment like St Joseph. Various facilities concepts were examined in detail. The selected concept is a combination of a mobile floating facility for the injection water treatment and chemical injection packages and a platform-based facility for processing the produced fluids/chemical. A pilot injection prior to full implementation has been planned to manage key subsurface/surface uncertainties and main challenges. The detailed studies of the pilot design and implementation are presented in a separate paper.
Description. Low salinity water floods and chemical enhanced oil recovery (CEOR) injection (Alkali, Surfactant and Polymer) are two technologies which have been applied onshore but are now being studied for use in new and existing offshore field developments. Their application offshore introduces several issues, which can significantly affect the technical feasibility and commercial viability of the project.
1. For "Greenfield?? and "Brownfield" projects the most suitable location of the CEOR facilities to minimize additional field infrastructure costs,
2. For "Brownfield?? projects the most suitable location of the CEOR facilities to optimize logistics, maximize safety and minimize the impact on ongoing production operations, during both the construction and operations phases,
3. The most suitable time in the field development schedule to install the CEOR facilities to maximize the availability of reservoir data and to minimize the initial platform costs.
The results presented in this paper are generic but they provide a basis for further study of the application of a dedicated desalination / CEOR vessel using specific field information. A work sheet has been provided in the paper identifying the most likely design concept(s) of a dedicated CEOR unit for a range of different field location parameters.
Results, Observations, and Conclusions.
In many cases the lowest risk and most cost efficient design is to locate the desalination / CEOR facilities on a separate vessel. This paper addresses the comparison of these issues in a qualitative manner for different design scenarios. The concept selection comparison is based upon engineering studies and typical offshore industry cost metrics.
This paper presents a basis for considering a dedicated CEOR vessel for offshore projects. This is a novel concept and by initiating further detailed analysis for specific field developments this paper could provide the impetus for the recovery of a significant amount of additional offshore field reserves.
The application of Enhanced Oil Recovery (EOR) technologies such as low salinity water floods and Alkali, Surfactant, Polymer (ASP) water floods, to oil field developments is not new to the oil industry but the application of these technologies to offshore fields is new to the oil industry. . Reduction in chemical costs as well as increased knowledge of the reservoir through 3D seismic data and improved computer modeling has made the application of EOR technologies offshore economic in many cases. These technology improvements, as well as the difficulty in accessing new exploration areas and the political drivers to maximize national resources, has made the application of EOR to the relatively large offshore fields, a higher priority within the major, national and independent oil companies.
Chai, Chon Fui (Sarawak Shell Berhad) | Adamson, Garold R. (Shell) | Lo, Sho-wei (Shell Technology India) | Agarwal, Binayak (Sarawak Shell Berhad) | Ritom, Simon (Shell) | Du, Kuifu (Shell) | Mekarapiruk, Wichaya (Petronas) | Jamaludin, Maisarah (Petronas) | Zakaria, Nur Atiqah (Petronas Carigali Sdn Bhd) | Din, Azmi (Petronas Carigali Sdn Bhd) | Azizan, Norlia
Chemical enhanced oil recovery (cEOR) is a complex process which exhibits a number of risks and uncertainties. A successful chemical EOR implementation depends on the success and the ability in addressing all these risks upfront and one of the important de-risking steps is the piloting process before full scale implementation.
St Joseph is an offshore field in North Sabah region of Malaysia chosen for chemical EOR implementation. In line with the implementation of chemical EOR, there are a number of uncertainties and risks associated with such a development. Some key uncertainties are generic to cEOR development, such as the heterogeneity, chemical effectiveness, emulsion, production of sales specification oil, etc. However, there are certain risks and uncertainties that are typical for this particular field, such as fractured injection, offshore environment, large secondary gas cap, etc. In order to de-risk the full field development and get a better handle on the risks and uncertainty, a pilot is planned.
The paper discuses the approach taken for the pilot selection, which includes the qualitative and quantitative assessment of pilot types vis-à-vis key risks, the workflow towards designing the pilot, the modeling approach followed, the facility concept of the design, and injectivity modeling, leading to final pilot design. The paper also touches upon the data acquisition and surveillance plan to analyze the pilot performance and quantitatively address the key risks.
In addition, the risks and uncertainties of the pilot implementation are also discussed, together with the mitigation and remediation methods. The pilot study resulted in the detailed pilot design and data gathering plan. The results of the pilot will be used to determine if chemical EOR is viable for full field development at St Joseph.
Introduction/Description of St Joseph Field
The St Joseph Field is a SW-NE tilted anticline with a structure dip of approximately 15o (varies from 10o to 20o). The field is comprised of number of stacked reservoir units. Potential cEOR is focused on the main reservoirs containing medium gravity oil. These reservoirs contained about 80% of the total field STOIIP. Lateral and vertical communications within BCDE sands are generally good. Production started in 1982. The reservoir pressure has declined from an initial pressure of about 1000 psi to a current pressure of 500 psi, in spite of the crestal gas injection that commenced in 1996. This crestal gas injection has
created a significant secondary gas cap in the St Joseph field. Water injection capacity of 60,000 b/d from six horizontal wells with smart well completions was recently installed. Water injection started in March 2011. Figure 1 below shows the location of the St Joseph Field.