PNPR cluster consists of three fields, namely PX, NX and PR (combined STOIIP ~200 MMstb), located ~300 km offshore of Peninsular Malaysia. Throughout its journey of monetizing marginal waxy crude, many challenges and hurdles have arisen, including sustaining oil production rate above economic threshold, pipeline clogging, and FPSO fuel uncertainties, which requires collaboration between surface and subsurface team to develop unique solutions in managing these downturns. Critically, PNPR cluster is expected to reach economic limit within few years’ time. This paper will elaborate on how IOR is achieved in PNPR cluster, historically and in near future. Ever since first production by PX and NX in 2004, infill drilling campaigns have been needed to sustain production above the economic limit of 5,000 bopd. Later in 2009, approximately a year after PR kicked off its first oil; the14 km pipeline to FPSO was plugged due to wax accumulation as a result of prolonged shutdown. A pipeline restoration project was embarked on involving installation of pipe in pipe (PiP), which utilizes hot water circulation as pipeline heating element. Another complexity has been consistently supplying gas to the FPSO for fuel, which involves a cement packer and adding perforation jobs in gas wells. Additionally, the waxy crude in these fields requires gas lift to be produced, particularly after water production started to escalate. This gives an opportunity to introduce through tubing electrical submersible pump (TTESP) to the field, while reducing dependence on gas lift. Financial wise, cost optimization initiatives are necessary to maintain the operability of the fields. To date, five infill projects have been successfully completed, contributing to IOR by bouncing back PNPR oil production rate. Additionally, a gas cap blow down (GCBD) from NX J80 reservoir also managed to improve reservoir recovery factor (RF) while supplying additional gas for fuel. Meanwhile, the PiP system, an enabler for IOR, has successfully ensures smooth crude oil delivery above pour point temperature from PR Platform to FPSO. In terms of gas fuel supply forecast, proper gas wells production phasing is planned to secure steady supply until 2023. IOR through artificial lift, TTESP is planned to be executed soon in one idle production well with potential gain of 500 bopd, hence eliminating option to workover the well, which is costly. Viewing IOR from economic standpoint, operating expenditure (OPEX) reduction through new philosophies were implemented, including reduction of FPSO charting rate, proactive maintenance and low-cost chemical bull heading, resulting in better cash flow for PNPR. It is expected that existing PNPR wells can recover 2 MMstb of oil through extension of economic life via incoming infill drilling in 2021, translating into 1-2% increase from current RF. Moreover, PX and NX already produced ~80% more reserves than originally booked in the first FDP.

Objective/Scope Applicability of Enhanced Oil Recovery (EOR) processes is gaining interest among offshore operators in recent years. CO2/miscible gas injection and Water Alternating Gas injection (WAG) are the most attractive EOR methods being considered by most offshore operators. Due to limitations imposed by the surface facility, any process optimization done through standalone reservoir simulation could be unreliable as the facility constraints and its effects are neglected. In order to minimize risk and reduce uncertainty, successful modelling and optimization of such projects requires integration of subsurface modelling with surface facility model. In this work, field development and optimization of a complex offshore production system, from a Pre-Salt carbonate reservoir offshore of Brazil is studied. Different field development scenarios, including water flooding, miscible gas injection, and WAG injection, are considered. Compositional fluid model is used in order to correctly model the fluid mixing effects and miscibility. Pressure change and thermal effects are considered in all the facility equipment. The complexities of the surface network, including gas sweetening, compression, and fluid blending are included in the integrated model. A new multi-user, multi-disciplinary Integrated Production System Modelling (IPSM) tool is used to fully-implicitly couple reservoir simulation with surface facility model. Production from the offshore asset is optimized for different development scenarios. The provided IPSM approach optimized operational schemes that were consistent with the constraints of the offshore facility. Additionally, with this new approach, all users from different disciplines were able to collaborate seamlessly, and any possible inconsistencies and discontinuities that could occur due to use of multiple decision making tools were removed. The use of integrated production systems modelling for optimizing EOR schemes in offshore assets, particularly miscible WAG, is proved to provide more robust answers. The complexities and Uncertainties of such processes, for both reservoir and facility models, are successfully studied.

Development of greenfield-type fields with a gas cap and oil rims on the shelf of Sakhalin Island is always associated with a high level of geological and technological risks. To assess the investment attractiveness of the projects, it is necessary to provide an in-depth elaboration of the concept, considering many uncertainties of both the geological structure and the development strategy and the subsea construction scenarios. A modern approach to risk assessment involves the mathematical modelling arrangement of the entire chain of technological processes from the interpretation of seismic data to the calculation of the material balance of the installations for the preparation of produced products. Integrated modelling at the current stage of technological development allows exploring many combinations of uncertainties in terms of the impact on the final hydrocarbon production profile and, accordingly, the economic indicators of the project. Possibilities of integrated modeling today are not limited to conceptual field design development. The result was the creation of an effective production planning tool for one of the most promising offshore fields of Sakhalin Island.

Self-service analytics refers to systems where business users are able to access relevant data, investigate data history/relationships, perform statistical and other types of analyses, and prepare their own visualizations. This allows business analysts/users to do their job without requiring support from the IT organization, thereby facilitating data democratization. Traditional business intelligence (BI) tools are not ideal for the task described above as they struggle to connect data from the wide range of industrial process data source types and integrate it into a model that is BOTH accessible to, AND understandable by, the broadest range of users in the organization. These platforms still require a degree of design and support expertise that is accessible to only a select subset of people in the organization; they do not fully enable data democratization yet. An alternative approach is to use software that is designed to work efficiently with data ranging from real-time process monitoring, process historian, relational, web services, big data, structured data files, and many other structured and semi-structured data sources. This paper describes an approach whereby operations intelligence software is used to connect disparate data sources, organize information, and provide visualization in a context that makes it accessible and understandable by users of any discipline in the organization. The openness and accessibility of operations intelligence software allows the layering on of advanced simulation and modeling, advanced analytics, and many other types of advanced information platforms, further extending the capability and comprehensibility of the information in any direction the user groups desire. It truly democratizes the data to empower the widest range of people to both contribute to the data AND benefit from it. In order to address the challenge of democratizing access to data, we will review the first steps required to get there: data aggregation and contextualization. We will explore how this powerful tool set leverages the concept of contextualization to frame data housed in complex data models in different ways for the benefit of different audiences. We will follow through with extending this benefit of contextualization to provide access to users who want information from advanced data processing platforms, such as simulators and analytics platforms, without actually needing to have expertise in using these advanced platforms. Finally, we will explore "self-service analytics." The proliferation of self-help BI dashboarding tools in the marketplace would lead one to believe that this is not a new concept, and indeed it is not new from the perspective of classic enterprise BI applications. What makes it exciting and new to this audience is the opportunities that are opening up to leverage these self-serve toolsets in the context of industrial owner operators. A properly implemented self-help toolset that is designed for, and caters to, the industrial business will enable engineers and non-data science experts to conduct their own investigations using process data as well as any other type of data. As a result, industrial business users are easily empowered to extract and understand the substantial value hidden in the insights their data contain. The architecture required to provide this solution, along with the many advantages it provides, will be discussed in the paper.

The objective of this paper is to show the value of using real time remote monitoring system (Automation) in offshore wells and to show a case study from Company for how we successfully used the system to detect well anomalies in real time and perform the suitable corrective action to optimize the well production and maximize well recovery with minimum man-hours. Our company is a leading Egyptian petroleum company with + 200 oil producers on 70 offshore platform; 27 % of platforms include automation system, in platforms without automation system we detect wells problems by performing periodic site visits and check the operating parameters per well., normally it take weeks between two successive platform visits. For platforms with automation system, we install pressure sensors on WH, Manifold, and casing head and temperature sensor on WH., The data being transferred from sensors to office instantaneously, which we successfully made use of, to respond quickly to the problems and achieved maximum well recovery. The offshore oil producer well J-100 was drilled and put on production on Nov. 2015, the well was producing naturally from the attic of the reservoir, it was a mandatory to control the production rate to keep the well producing beyond the calculated critical production rate to avoid water coning. After a while of putting the well on production, well sensors showed several successive abnormal changes in readings which had been captured in real time with the help of automation system, and with data analyzing we found the causes of each phenomena every time (like loading up, a problem in the production choke, etc.) and we succeeded to prepare the action plan, and perform the scope of work as soon as possible. Without the automation system, it would take weeks to detect the problem based on the site visits plan. However, installing the automation system will enhance the response efficiency by saving the time required for problem detection, and improving the quality, density and accuracy of well data. In addition, it will decrease the losses in production rate, and maximize the recovery by optimizing the production rate based on the field depletion plan. In summary, this paper discussing a case study for the value of using real time remote monitoring systems in offshore fields and we used this case to highlight the need to expand the system to include more wells in our field to maximize the field recovery and add considerable benefit to the business.

This paper uses a case study approach to present the challenges to develop a large and thick oil carbonate reservoir that is full of opportunities and uncertainties. The Libra block, located in Santos Basin ultra-deep water, in Brazil, has been developed under a Production Sharing Contract that was awarded to a Consortium where PETROBRAS is the operator in partnership with SHELL, TOTAL, CNOOC Limited and CNPC. This document will briefly present the de-risking plan, and detail the EWT Program implementation and its impact on the Mero area development, which consists of up to 4 (four) mega projects and altogether represents over 20 billion dollars in CAPEX investment. In addition, the results will show how the achievements achieved by the EWT project provided an extensive technological legacy to the offshore oil & gas industry.

The FPSO Kaombo Norte came on stream on July 27 th offshore Angola. When both its FPSOs will be at plateau, Kaombo, the biggest deep offshore project in Angola will account for 15% of the country's oil production. It produces light oil from six fields scattered over an 800-square-kilometer area. Gindungo, Gengibre, and Caril fields are connected to the Norte FPSO while Mostarda, Canela, and Louro fields will be producing on FPSO Sul. The full development stands out for its subsea network size with more than 300 kilometers of lines on the seabed within 1500-2000m water depth, including subsea production wells more than 25km away from the production facility. In order to secure a safe First-Oil and to smoothly start-up the production, a detailed and cross-functional study was carried out. The first step was to start from a clean slate by forgetting all previous startup scenarios: the three loops candidate to start-up hydrocarbon production were re-analyzed in depth to evaluate strengths and weaknesses. A task force composed of all involved disciplines, including contractors, was put in place in order to apply a cross-functional approach. Constraints from reservoir up to topsides were analyzed providing an overall picture and clear ranking to develop the start-up strategy. An ambitious planning of the commissioning activities combined with a relatively short-term reservoir management were crucial to lock production loop priorities with water injection and gas export systems readiness. The work jointly performed contributed to serene environment for a safe start-up and ramp-up. Following the assessment, decision was made to start first the most "powerful" reservoir despite a challenging flowline. The relatively high initial pressure and oil undersaturation, the robust open-hole gravel-pack completions and high productivity wells were beneficial to stabilize the multiphase flow in the subsea network. Improvement of the production was rapidly made with the start-up of the second production loop only fifteen days after. Postponement of the water injection system and the availability of the riser base gas lift were judiciously calculated: the readiness of these systems arrived in due time to respectively slow down the natural depletion of the reservoirs and improve the wells eruptivity and stability of the flowlines. Our capacity to re-invent ourselves and leave behind individual priorities conducted to a collective success captured in the outstanding production levels since early days of field life.

Disintegrable metal (DM) has proven its market value since the first set of disintegrable frac balls were successfully employed in a shale well in Bakken field about 10 years ago. The DM material technology and tools have changed the downhole tool operation landscape with unprecedented efficiency, reliability, by reducing the operational complexity or simplifying tool installation or actuation procedures. This paper reviews the advancement of DM materials technology, arts to engineer and control the disintegrating performance, various DM downhole tools, and the field operation case studies over the last 10 years. Review of the art of disintegration of disintegrable metals is based literature surveys and author’s own research and development results. Disintegrable metals currently available on the market could be classified into two different metallic systems based on their base metal chemistry: magnesium based disintegrable metal and aluminum-based disintegrable metal. Both systems are light weight, strong as steel and completely disintegrable in typical downhole environments. The paper will review the material design, microstructure, and properties of the two metallic systems, then discuss how to match material properties with requirement of downhole disintegrable tools, and finally share field operation cases. Most of DM materials have micro-galvanic cells built into their microstructures and disintegrate through galvanic corrosion when contacting with wellbore fluid. Key variables affecting the rate of disintegration include material composition, well temperature, tool surface area exposure to a fluid, fluid type, concentration and agitation conditions. The review reveals that it is critical to select the correct DM material to match the application environment for a successful field application of disintegrable tool. In today’s multi-stage hydraulic fracturing market, DM tools would be the preferred technology of choice when DM material selection and tool design and performance match properly to the needs of hytraulic fracture operation of a well. The thermodynamics and kinetics that control the disintegration performance of DM tools, or the art of disintegration, will be reviewed and shared with the readers. The profound arts and engineering of DM materials and field case studies shared by this paper would shed light on how to make sound selection of DM materials, design optimal DM tools for a defined well or field application, develop the best field operation procedures, and execute a MD application efficiently.

This paper addresses the innovative appraisal strategy applied to the Libra project; located in ultra-deep waters offshore Brazil. It details the key role of the Extended Well Test (EWT) Program, within the field overall Risk Mitigation Plan, as well as its interfaces with additional appraisal activities. The Value of Information (VoI) for the main acquired data is described, highlighting the associated impacts for the full field development and validation of the enhanced recovery strategy. A case study approach details how the whole EWT project maximized the acquired information, mainly from a reservoir point of view. Although the EWT approach is not new to Petrobras in the offshore environment, this is the first one with simultaneous oil production and gas reinjection. Several reasons justify the use of the industry’s first dedicated offshore EWT system with this capability. Gathering data on the main dynamic parameters of the field was critical to speed-up the development, with an acceptable risk level. The incorporation of these data in the reservoir models and the impacts in the most relevant development decisions are also described. The chosen methodology brought many opportunities, as well as challenges to interpret the data and to incorporate them in the reservoir models. Furthermore, the capability to produce without continuous gas flaring makes it possible to apply such approach anywhere else in the world.

The first subsea multiphase boosting system was installed in 1994 and it is today a proven technology with a global track record. In addition to bringing increased production and recovery, multiphase boosting may also reduce flow assurance issues, reduce project CAPEX and OPEX, improve operability and safety as well as reduce the greenhouse gas emissions when compared to gas lift, the default lifting solution. A review of the evaluation process and drivers during subsea artificial lift evaluations over the last three decades indicates that in general only a few of the actual upsides of subsea multiphase boosting have been considered, suggesting that there is a need for a more complete overview of the advantages and an approach to uncovering and quantifying the actual value. This paper discusses the different aspects of subsea multiphase boosting through a comprehensive list of tangible benefits that may support the field development decision process towards identifying the potentially significant and hidden value of subsea multiphase boosting. Referencing experience from more than 30 installations it also provides a historical summary of the various aspects of subsea boosting and which drivers were and were not considered during the decision making process.

One of the most promising Enhanced Oil Recovery (EOR) methods is CO 2 injection. However, if the oil contains asphaltenes, CO 2 injection may cause asphaltene precipitation and introduce production related challenges. Conventional three-phase (gas/oil/water) compositional simulators are unable to predict precipitation of asphaltenes and multiphase compositional simulators are required. The use of detailed multiphase equilibrium calculations is very CPU intensive and commercial simulation packages often employ a hybrid model that may not capture the true physics at play. Conflicting findings have been reported from experimental and theoretical studies: Some studies show that Asphaltene deposition, due to CO 2 injection, takes place near the injection well, while others have reported that asphaltene deposition occurs near the production well. True multiphase equilibrium calculations can be used to demonstrate that both findings are possible and that many factors will affect the deposition behavior. Accordingly, a general statement such as CO 2 injection causes more asphaltene precipitation relative to hydrocarbon (HC) gas injection is not always true. This added complexity indicates the need for multiphase compositional simulation to delineate asphaltene deposition behavior and quantity. In this work, we propose a four-phase compositional simulator (gas/oil/asphaltene/water) to predict the asphaltene precipitation during CO 2 and HC gas injection processes. A new hybrid formulation, based on a simple table look-up approach, is introduced to replace detailed multiphase calculations (gas/oil/asphaltene) at a CPU requirement that is comparable to two-phase (gas/oil) equilibrium calculations. A range of simulation models/scenarios are presented to test and validate the new formulation against detailed multiphase compositional simulation, and we demonstrate an excellent agreement between the hybrid model and the full multiphase calculations. The proposed approach is easy to implement in commercial tools and provides a path to allow for more detailed studies of asphaltene precipitation and related production challenges.

Unconventional resources have significantly transformed the landscape of the oil and gas industry. The primary recovery factor ranges anywhere from 2% to 8% for the various shale plays throughout the United States. Hence, it is imperative to exploit the vast potential of unconventional reservoirs and increase the recovery factors beyond primary depletion by implementing improved and enhanced oil recovery (IOR/EOR) methods. This paper presents detailed review of the advances in IOR/EOR technologies applied to unconventional oil reservoirs. A thorough review of the pertinent published literature on IOR/EOR was performed. Results of EOR application to unconventionals shared by various operators in their investor presentations and press reports were also analyzed. The IOR/EOR studies were classified into laboratory experiments, numerical modeling and field laboratory trials (pilots). In addition, the field trials were also analyzed based on the representative shale plays. Most of the studies performed for the application of EOR technologies to unconventional oil reservoirs have been limited to experimental investigations and numerical simulation studies. The research revealed that miscible gas injection (produced gases, CO 2 , etc.) is the most promising method among the EOR techniques (miscible gas, water flooding, surfactant, chemical and polymer). Experimental studies showed that CO 2 injection had the highest potential of improved recovery in unconventionals followed by produced gas injection and that diffusion was the most predominant mechanism. Surfactant injection showed the next best potential to increase oil recovery by altering the wettability of rock in laboratory experiments. The gas injection pilots showed that sufficient injectivity was achieved mainly due to the injection induced fractures and did not exhibit any significant effect of diffusion. Conformance control remains a big challenge especially due to the channeling of the gas through the fractures. Produced gas injection pilots in the Eagle Ford formation have demonstrated the greatest success in increasing oil recovery. However, there are many inconsistencies between the laboratory investigations and field trials that needs reconciliation. Further research is necessary to bridge the gap and improve the scaling from laboratory to field. This methodical study elicits the learnings and challenges from the application of different IOR/EOR technologies to unconventionals at various scales (micro to macro to field scale). In addition, ideas for future research are recommended to improve the understanding of the complex mechanisms of EOR in unconventional oil reservoirs. These include optimizing gas injection schemes (huff-n-puff, continuous injection) based on key parameters such as permeability and investigating fracture placement for improving the drainage area and inter-well communication.

The oil and gas industry loses approximately $300 billion profit annually to poor operating performance. Outdated technologies and work practices are largely to blame because they lack the predictive capabilities of modern automation. When oil and gas producers adopt modern technologies and adjust work processes, they can recover a significant portion of these losses and realize top quartile performance in production, reliability, and safety. Examples illustrate this. In response to low commodity prices, the oil and gas industry has rationalized operations and procedures over the last few years. However, estimates are that the industry still loses hundreds of billions of dollars annually to poor operating performance. Much of that can be recovered by emulating the practices of the industry's best performers. The top quartile of oil and gas producers deploys technology, processes and people in a purposeful orchestration to boost production, cut costs and improve safety. They define a strategy, analyze inefficiencies, prioritize opportunities, and then select technologies that can scale and leverage existing investments. Doing this substantially boosts the bottom line.

The Stampede deepwater field is located in the Gulf of Mexico, Green Canyon block, and consists of approximately 3,500 ft of water. The Stampede project will include 10 in-service wells in a Miocene formation for a reservoir system at 28,000 – 31,000 ft. TVD. This unique reservoir has deep wells, a low gas-to-oil ratio, and a low bubble point, a combination that calls for an in-well gas lift injection design. The Stampede project team identified dynamic simulation as a validation tool during the early design phase. High-fidelity fully compositional models were developed for Subsea to simulate heat-transfer effects in the well annulus to understand the interaction between production fluid and gas lift injection for various startup cases. After the simulation model was in place and in use, the project team identified the need to continue using the topsides and subsea integrated simulation models to validate additional phases in process design and engineering. We developed a multi-purpose dynamic simulator (MPDS) that proved to be a crucial tool for Standard Operating Procedures (SOPs) validation, Operations training and control system checkout. The use of this integrated model provided tangible economic benefits because it led to better informed design decisions throughout the project lifecycle, minimizing workarounds. The challenges the project faced were solved by using the simulator, which connected all the systems together: the subsurface equipment and artificial lift method, the risers and production facilities, and the export pipelines pumps. Using the whole platform model, the project team was able to identify and solve potential issues before they became problems. This paper shows how a simulator with dynamic full-facility components (subsurface, subsea, hull, and topsides) was used by the project team during each project phase (design, FEED, and construction) to benefit various disciplines (Reservoir and Flow Assurance Engineers, Operations, Automation, and Initial Startup teams). The paper refers to case studies and specific challenges faced by the project team to develop conclusions from the lessons learned and insights gained.

Riser Base Gas Lift is one of several methods successfully deployed that can enhance production and suppress severe slugging. With few moving parts, it is a solution that can be accommodated into existing infrastructure with minimal upgrades on existing facilities while not being as maintenance intensive as other solutions. The flow assurance design is critical to successful implementation and this paper details this process through the means of a case study. The case study in question is a three well, deep water subsea tie-back. The subsea system consists of an 8" × 12" pipe-in-pipe round-trip piggable flowline loop which will experience severe terrain slugging. Riser base gas lift had been implemented with success on adjacent fields at this facility; therefore it was again selected for deployment. From a Flow Assurance perspective, design considerations discussed are: Optimum Injection Rate/Operating Range: Flowrate requirements that will effectively mitigate slugging and will not violate any operating constraints. Low Temperature Mitigation: Design against brittle material failure. Erosion Control: Assessment of droplet erosion. Production Chemistry: Design to prevent formation of hydrates/asphaltenes in the production system due to injection of gas. Testing/Benchmarking: Since system design is heavily dependent on the accuracy of simulation modelling, details of equipment flow tests to validate performance are discussed. Recommendations/Support to Operations: Development of standard operating practices associated with gas lift. Execution Issues: Detailing design adaptations to system changes during installation etc. Revalidation: Review of actual operational performance against design intent. For this field, a novel technological solution of a gas-lift umbilical riser was selected. This configuration provides the best balance of operability, reliability and cost. The operating philosophy uses a fixed subsea orifice /topside choke to control the gas flow (rather than the conventional variable subsea choke). The orifice will regulate the injection rate even as the system pressure varies due to slugging, allowing the umbilical to act as an accumulator that dampens the pressure variations and allows for a larger bandwidth and smoother operation. Ultimately this configuration is envisioned to be less dependent on operator interaction.

Abstract Asphaltene precipitation and subsequent deposition is a potential problem in oil production because the significant costs for wellbore cleaning and the associated production loss. To better understand the mechanisms by which asphaltenes precipitate and deposit, in this work we present experimental evidence that supports the idea that precipitation and aggregation of asphaltenes is a multi-step process, where the former is driven primarily by thermodynamics whereas the latter is driven by kinetics. Under this multi-step mechanism, asphaltene precipitation is a fully reversible process. On the other hand, from the precipitated phase, subsequent aggregation and aging leads to the formation of more solid-like structures. Furthermore, we also present experimental results that suggest that the currently available commercial technologies to detect asphaltene precipitation (i.e. NIR spectroscopy and High Pressure Microscopy) might not be appropriate to detect the exact point of asphaltene precipitation, but instead they give a combined reading of precipitation plus aggregation. For this reason, the results obtained using these methods are very sensitive to the depressurization rates. The better understanding of the asphaltene behavior has enabled the development of an enhanced modeling approach based on the Perturbed Chain version of the Statistical Associating Fluid Theory equation of state (PC-SAFT EOS), which is used to predict the precipitation of asphaltenes at reservoir conditions and requires fewer simulation parameters than previous methods. A case study is presented in which our modeling technique was proven useful for the detection and correction of inconsistencies in experiments done using a bottom-hole sample at reservoir conditions.

Abstract In recent years, the number of subsea wells has increased steadily; a 2011 report estimated more than 5,500 worldwide. One of the key challenges the industry faces with subsea wells is generally lower recovery factors compared to wells with surface access. A key reason for this difference is because workover activities to improve recovery rates in subsea wells has traditionally required use of large rigs, risers, jointed pipe or coiled tubing (CT), with high operating rates. The high costs of these operations can make it difficult to achieve the necessary increases in production rates and revenue to justify the workover investment, even with increasing oil prices; therefore, operators often forgo production-improvement workovers. However, a growing global population and soaring energy demand means that operators are facing increasing pressure to maximize production and value from mature assets. These challenges have spurred development of alternative, lighter weight, more cost-effective intervention methods to enhance recovery rates in deepwater, subsurface wells. These alternative technologies include electric-line tools that can be run from smaller, dynamically positioned light well intervention vessels, instead of large workover ships with risers. These rigless and riserless light well interventions (RLWI) improve scheduling flexibility and reduce costs, thereby reducing barriers to performing subsurface well interventions and enabling subsea operators to realize oil recovery rates of 50% or more. Today many industry companies have a clear tendency to migrate towards lightweight, more cost-effective alternative solutions. But for some, misperceptions still exist and skepticism remains for using RLWI for deepwater subsea wells. However, over the past decade, RLWI has achieved a solid track record of demonstrated value and is an inherently safer method for subsea well interventions, compared to conventional heavier methods. This paper describes the opportunities to improve recovery rates in subsea wells using the lighter, more efficient and ultimately more productive RLWI methods. Using these techniques has enabled operators to conduct routine planned access to subsea producing assets, improve surveillance and management of interventions, and, ultimately, increase recovery rates. Several case histories and examples are presented. Introduction Challenge: The Need to Increase Production from Existing Assets to Meet Growing Global Demand for Energy. Looking at peak oil production from a number of the major oil producers shows that many of them have reached peak oil production over the last ten years (Table 1) the industry is striving to find new resources to replace diminishing reserves and to meet increasing global demand; these factors are moving exploration and development into deeper water offshore, where currently more new fields are being developed subsea than from platforms (Strategic Offshore Research Ltd. 2012).

Abstract This paper describes and highlights, via two case studies, the benefits of conducting rigless subsea well intervention from specialist monohull vessels. The case studies provide an overview of the operations on subsea wells, from intervening through the production tree (XT), to XT change-out and well P&A / wellhead removal operations. A brief overview of rigless intervention techniques and equipment is also described. The operations described in the case studies were completed in two very different operating regions. The United Kingdom North Sea (UKCS) and West Africa (Equatorial Guinea). In the first case study, the paper describes how over a 68 day period a Light Well Intervention Vessel (LWIV) successfully and safely performed mechanical repair & well maintenance (and well integrity surveillance); data acquisition (production logging), well suspension (for a XT recovery); scale-squeeze pumping operations (production enhancement) and finally well plug and abandonment (decommissioning) on a variety of wells across several subsea Fields. The second case study summarises a 105 day campaign in which a LWIV was contracted to undertake subsea well interventions (for both well maintenance and production enhancement needs) and a temporary well suspension (for a XT change-out) on multiple subsea wells within a Field. The vessel optimisation, through performance, coupled with its ease and speed of transit and set up (DP3 rated) were key to this particular campaign as the 7 wells identified to be worked on by the Operator were a number of kilometres apart precluding the efficient use of a moored unit. Introduction Rigless and Riserless Light Well Intervention (RLWI) activities have been executed for over 25 years across the North Sea. The purpose of these case studies is to demonstrate that with effective project management (planning, developing, execution and close-out) the use of RLWI is both a flexible and extremely cost effective method which Operators can utilize for a single well, or across a number (a campaign) of subsea wells, irrespective of subsea tree type or close proximity. Case study #1 outlined below summarizes the flexibility & efficiency of multi-service LWIV in the North Sea with the ability to perform intervention/subsea operations in a cost effective and efficient manner, allowing remedial operations to be conducted in order to maintain well integrity, and other remedial well servicing techniques in order to maintain and often enhance hydrocarbon production (manage life of well productivity) before eventual Cessation of Production.

Abstract The Monobore, High-flow, ROV Operable Connector is a male and female connector and seal system designed for use subsea in small bore gas and fluid piping applications. This system's principle attribute over traditional methods is its ability to be installed in " free fly" fashion, by a typical work class Remotely Operated Vehicle, similar to hydraulic flying leads in production control system applications. Latching of the type of connector is similar to conventional hydraulic junction plate technology. The tooling required for this operation is also similar to the make-up of hydraulic junction plates utilizing an API 17D class 4 torque tool, flying lead orientation device, and any other easily attachable and detachable stability aides or weights. To meet these operational scenarios, the connector must be light, made of corrosion resistant materials, and have an extremely reliable sealing mechanism. This system must also be easily configured into a " flying lead", where the tubing or piping is both strong and compliant. This paper describes just such a connector system that is designated as the M5. For the matter of this paper, the removable half of the connector will be referenced as ‘removable connector’ and the fixed half of the connector will be referenced as ‘fixed connector’.

Abstract The Greater Vanza Longui Area (GVLA) field is located in Area B of the offshore Cabinda, Angola Block 0 concession. GVLA is a multi field development and will target hydrocarbon resources in the Cretaceous Pinda formation that contain reservoirs with rich gas condensates and underlying volatile oil rims. The objective of this paper is to demonstrate the rigorous subsurface evaluation process employed for developing a large offshore gas condensate field. The strength of the reservoir evaluation is the large amount of good quality appraisal data gathered and used to benchmark subsurface inputs. There have been 6 reservoir penetrations, 4 DSTs and 3 full reservoir cores and multiple fluid samples. A structured workflow was followed to identify and incorporate the uncertainties in the subsurface assessment. Probabilistic forecasts helped to fully characterize and realistically assess the uncertainties. The uncertainties were grouped mainly into static and dynamic categories. The impact of the static uncertainties was assessed using 3-D geological models. Geologic models were built upon a core-based sequence stratigraphic framework for the Pinda formation. The facies, petrophysical properties and top depth of reservoir were varied to capture the uncertainty ranges seen in the GVLA wells and analogue fields. These models captured the net-to-gross uncertainty which has the largest impact on hydrocarbons in-place and connectivity. The dynamic uncertainties were assessed using statistical design of experiments. Monte Carlo simulations were employed to generate the probabilistic estimates. Reservoir simulation with the compositional formulation was used as the primary forecasting method. Robust equation-of-state models were built to appropriately quantify natural gas liquids (LPGs) which were value drivers for the project. Various development alternatives (primary depletion, gas injection) were evaluated and detailed economic analysis were performed for concept selection. The production forecasts were verified with material balance models, analogues. Introduction The Greater Vanza Longui Area (GVLA) is located in the western portion of Block 0 of the offshore Cabinda Province, Angola. The GVLA project area is approximately 12km by 12km, and ranges in water depth from 300ft to 600ft. Sonangol, Total and Eni are partners in this project with Chevron as the operator. The project area consists of five adjacent fault blocks (Fig. 1): Longui Main, Longui East, 79-B, Vanza, and 80-E, all of which have been grouped into two main development areas, Longui and Vanza. The GVLA oil and gas reservoirs are contained within the Cretaceous Pinda Formation (Fm.). The GVLA development is an attractive economic opportunity that will fill projected gas supply for the Angola Liquefied Natural Gas Plant (ALNG) project. The recommended recovery mechanism is primary depletion of the gas cap and oil column, with gas/gas liquids processing at Sanha FPSO and ALNG.