With soaring global demand, depleting supplies of crude oil coupled with the collapse in the oil prices, maximizing oil production in mature fields has become a priority. Such fields account for over 70% of the world's oil and gas production, with a worldwide average recovery factor of 35% for oil. Main challenge encountered by mature oil fields is the well pressure depletion over time, sand production and increased water-cut. Since pressure depletion is inevitable, it is particularly challenging to continue to produce as there is insufficient reservoir pressure to push the well fluids to the main processing facilities. As the reservoirs starts to deplete, other issues such as sand production and high water cut also becomes more prominent. The system discussed in this paper is an effective engineering solution designed for topside receiving facilities. The Multi Production Unit (MPU) is a low pressure production unit with integral desanding and dewatering. MPU is a system tailored to boost the pressure of production fluids from low pressure wells, while handling common challenges in mature fields such as high water cut and high sand production. The system is ideally suited for remote wellhead platforms where wells have insufficient pressure to deliver well fluids to production header in addition to flow assurance issues related to high sand and water production. Conceptual design of this system is based on the very low, almost atmospheric, operating pressure of the system, wherein the elements. The system is designed in such a way that it can receive continuous full flow from the well, and still manages–through intricate isolation methodology-to operate in batches. This batch operation arrangement allows for liquid accumulation which is then discharged to the production header after being pressurized. The integral desander enables sand removal from the production fluid before discharging the liquids to the production header. The accumulated sand can be discharged in batches whilst the system continues to produce. The dewatering feature of the system allows for removal of water prior to discharging the oilflow from the well to topside becomes easier without the need to inject the well itself with any foreign, resulting in reduced induced backpressure due to reduction in flow to the downstream system. Features of the system include: Compact design; Light weight; Self-contained system – no external utilities required except for HP gas source for motive gas and instrument gas/air supply; No pumps and power generation; Low system complexity and controls; Fully automated system No manning requirement; Sand handling; and Bulk water handling.

In a conventional shallow water field development with dry trees, fixed platforms are utilized to support the topsides processing facilities, dry-tree wellheads and well conductors. The fixed platform can be a fully integrated platform or a dedicated process platform and a wellhead platform. A new innovative integrated processing and wellhead platform concept by means of a suspended conductor guide support frame which is retractable, provides an alternative for the structural design of facilities for dry-tree field developments. This conductor guide support frame concept is developed for a Self-Installing Platform (SIP) such that it can support well conductors and dry trees, besides the processing facilities similar to a conventional fixed platform and does not require the mobilization of a heavy lift vessel for installation. Being self-installable, it can be easily deployed and redeployed at different sites and hence is suitable for marginal fields developments. A case study has been performed on this concept and the in-service structural stress and fatigue performance of the conductors have been verified based on design parameters for a typical development offshore Peninsular Malaysia. The range of suitable applications of this SIP with conductor guide support frame concept is presented.

Fixed offshore structures has predominantly been installed via the conventional crane barge, no matter whether it is small or a big structure. Utilization of a crane barge has resulted in a significant installation costs as the mobilization cost and the Daily Charter Rates (DCR) for the vessel is very high. Supporting the innovation agenda in an effort to better control project costs, the rig-installed platform concept is one of the option chosen to install small lightweight structure due to the cheaper cost of Jack-up Rig (JUR) day rates compared to a conventional crane barge. The savings in material, schedule and mobilization could be realized as the jack-up rig can proceed with the drilling of the wells (which are also the main piles of the structure) directly after the structure installation. As JUR is primarily used to drill oil/gas wells, some minor modification may be required to the JUR before it can be utilized to install small and lightweight offshore structures, both jacket and topsides, with some degree of limitations due to the drilling envelope and derrick lifting capacity. This ‘know-how’ has been around for quite some time in the industry by niche service providers, but was not regularly exploited in this part of the world as it has been a norm for the field development team to manage an installation contractor whilst the wells team manage a drilling contractor. This paper shares the learnings of a wellhead platform for a marginal field that was successfully engineered, fabricated and offshore installed using a JUR and eventually achieved 1 st Oil within 9 months of contract award at an installed cost below USD 29 Million. This paper will mainly discuss on the pre-requisites of JUR installed platforms, case for change, concept select and potential value creation to the overall project. The project referenced above has exemplified to the industry that JUR installed platform is a feasible option in this part of the world, with significant cost savings, contributing to a better economics for a marginal field project.

The objective of this paper is to share about the most recent decommissioning project in Malaysia which is Ophir Field Abandonment activity. Interesting facts about this project is most of the petroleum facilities are recovered and repurpose to re-use for other Field Development project. Upon successful abandonment of the field by August 2019, the wet tow transportation activity of the Wellhead Platform had been the 1 st of such activity in Malaysia, as well as the 1st offshore platform to be repurpose through decommissioning activity. Ophir field is a small production field located 210km North East of offshore Terengganu. Ophir development plan was installation of standalone-suction pile Wellhead Platform structure with few development wells. The oil is transported via means of flexible flowline into a Floating Production Storage & Offloading (FPSO) for processing prior to lifting for market needs. Such standalone-suction pile Wellhead Platform structure was the 1st installed in Malaysia. As Ophir operator monetizing the hydrocarbon, the field experienced several reservoir issues. Further technical assessment and economic scenarios were exhaustively evaluated. As a result of the exhaustive evaluation, the field had received Cease of Production certificate by PETRONAS to proceed with abandonment activity. Per PETRONAS Procedure & Guideline for Upstream Facilities (PPGUA) requirement, Ophir Abandonment Plan is reviewed and deliberated in 3 stages gated decommissioning review process known as Abandonment Review (AR). The stages review consists of abandonment project planning, Decommissioning Option Assessment and Decommissioning Project Execution. Decommissioning of upstream facility is a niche subject in Malaysia, thus educating various internal and external stakeholders were required in order to establish the key steps for the decommissioning execution. Liaison with related state agencies was done through Zone Economic Exclusive sitting, with Petroleum Safety Unit's (PSU) as the secretariat. PSU is one of the unit under Ministry of Domestic Trade, Cooperative and Consumerism (MDTCC) who is responsible in coordinating the policies, licensing, regulations and activities related to the safety of petroleum, petrochemical and gas industry in Malaysia. Ophir Abandonment project is uniquely interesting because most of the petroleum facilities and accessories such as flexible flowline, Wellhead Platform, FPSO mooring lines and anchors had been recovered, transported and repurpose for a new Field Development project. The Wellhead Platform weighted around 900 MT was removed via single lift method and wet towed 100 km to the new field and such wet tow activity is the first of its kind in Malaysia. Various engineering and structure simulation were conducted to ensure the abandonment activity scheduled in August 2019 executed smoothly without any HSE incident and impact to the environment. There were few great experiences and important lessons that PETRONAS had learned from this project. PETRONAS believes that the culture of sharing experiences and lesson learnt will be the epitome for each operators & contractors to work safely, stimulate creativity and strive towards decommissioning cost compression for every decommissioning project.

Zawtika Project is an offshore gas field located in the Gulf of Moattama, Myanmar with water depth ranges from 120 meters to 160 meters. PTTEPI has operated Zawtika field and brought it to production since 2014 with conventional wellhead platforms (CWP) development. The future prospects are expected to be smaller gas reservoirs which are not commercially developed with CWP. Thus, a minimum facilty platform concept study had been initiated after CWP cannot be economically justified to develop and maintain gas production plateau. The basic engineering study was conducted on the selected wellhead platform options namely Zawtika optimized conventional wellhead platform (ZOCP) and Zawtika minimum facility platform (ZMFP). These platform types will be chosen for EPCI based on the size of the candidate prospects after the post-appraisal well result is confirmed. ZOCP is merely a conventional wellhead platform with partial design optimization. On the other hand, ZMFP is a true minimum facility platform. This paper will focus on this type of platform. ZMFP capacity is reduced to match with the target prospects at 90 MMSCFD gas production. The facilities equipment and intra-field sealine are also reviewed and optimized. ZMFP is expected to reduce the CAPEX approximate up to 20% from (1) minimized well slots (2) commingled the flowlines (3) sweet gas material compatible selection. The unique design of ZMFP is the power supply comes from 100% solar power which is a new implementing concept. Estimated of the base weight of ZMFP is 17% lower than CWP leading to estimated CAPEX reduction almost 20% compared with CWP. However, due to the stability of platform under the water depth of Zawtika field condition makes the wellhead platform design to be a 4-legged jacket. Small improvement can be done at the jacket which is about 65% of the total CAPEX. Then an economic evaluation is carried out to compare the NPV of the existing platform design with the improved ZMFP, it found that NPV improve significantly almost 15 %. With the lowering down of the CAPEX, at this stage ZMFP design currently enables 3 sub-commercial prospects to be economically developed. ZMFP design is already selected to implement with the coming Zawtika phase 1D development for 3 wellhead platforms and now it is under EPCI preparation. Zawtika minimum facility platform demonstrates PTTEPI aims to maximize the resource recovery of the field by developing and monetizing sub-commercial reservoirs. With the above-mentioned objective, a new platform is engineered and designed to sacrifices some options down to its fit-for-purpose facility yet maintain the integrity and environmental friendly designs.

While industrial revolution 4.0 transforming the manufacturing industry with the adoption of computers and enhanced with smart and autonomous system that comes with big data and machine learning capability, operators in oil and gas industry also embarked on its evolution, advancing in end-to-end project delivery efficiency through simplification and transformation, with the objective to deliver best-in-class project in a consistent manner. This paper demonstrates a few key changes implemented by Civil, Structural and Offshore Engineering discipline to support the project delivery evolution by referring to a recent wellhead platform project Shell delivered. The principles of simplification and transformation were embraced since the early front end development phase, started from competitive scoping through the development of an intent/requirements-based technical requirements tailored to the project, considered all the key and relevant lessons learnt from respective operator combined with widely referred industry specifications. An intend-based design driven by efficient execution strategy has also shorten the fabrication and installation duration where early Mechanical Completion can be achieved by carefully bringing forward certain scope to front-end loading (FEL) with contractor's commitment to work within a stretched, proper-defined boundaries. Another key change project implemented is through the enhancement in supply chain model that aims to accelerate the delivery schedule. Contractors were empowered and took full accountability under the EPC contract, after alignment of project intent, goals and owner/contractor interest. Cross-organization collaboration between operating units also allow project and/or sub-systems across projects to approach market in a joint campaign, benefits all parties from economy of scale. The ultimate purpose of having efficient project delivery is to drive CAPEX down, enable more marginal fields development become economically feasible. Through the standardization of design requirements and smart replication, this will become the new baseline (in term of cost and schedule) to deliver future standard wellhead platform and transforming wellhead platform delivery to something like block manufacturing industry.

FIELD ‘A’ Project is presented as a low cost development concept for marginal oil field. The development concept consists of wellhead platform with a full well stream evacuation scheme through a flexible flow line to FPSO for further processing and subsequently for export. The unutilized associated gas is flared. As a part of cost reduction strategy and incentive, the Host Authority has approved a new contract model and technological approaches for implementation. FIELD ‘A’ Project is undertaken and monetized via a new approach of marginal oil field development under the Risk Service Contract (RSC). The uniqueness of the FIELD ‘A’ development concept is the technological introduction of re-locatable type fixed asset using Suction Pile Technology (SPT) for jacket installation thus allowing it to be transported and utilized at other potential marginal field within the asset design life. SPT is a traditional jacket with integrated suction pile foundation, which triggered significant benefit and long term cost reductions in the fabrication and offshore installation. The 1100 MT jacket is designed using suction pile technology that enables the platform to be relocated to other potential marginal field. SPT is proven to be a highly efficient and very swift concept where the jacket offshore installation campaign can be successfully executed in less than 24 hours as compared to the conventional jacket installation, which require several days of pile driving. Fabrication costs are reduced significantly since no requirement on the pile sleeves, catchers, centralizers, mud mats, and leveling pad eyes. Substantially, SPT jacket is proven to be that of one of the most cost effective in comparison to other re-locatable type offshore mobile facilities such as MOPU and MOAB. SPT is also integrated with scour protection; hence no seabed preparation or rock dumping is required. Therefore, the offshore campaign for SPT would promote lower installation cost, improved schedule and most importantly safety. In conclusion, the jacket with integrated suction pile foundation promotes and accordingly justifies the development of marginal field. In the current environment of low oil price, developing a new marginal field in such a way is necessary so as to maintain or improve the overall economic of the project. This fit for purpose and hybrid SPT concept with a rigid substructure that can be easily relocated is definitely worth to be implemented.

In today's environment drilling, well workover and well intervention operations call for increased efficiency and safety. Concurrent operations are a method to increase efficiency. However safety should not be compromised. An innovative device has been developed to enable SIMOPS (Simultaneous Operations) from a jack-up. An analysis has been made to identify which operations, when executed from a jack-up, would benefit from the possibility to be done concurrently. Typically most well operations are done through the rotary table. Those operations are either using drillpipe, wireline or coiled tubing. The operations are thus often sequential and allow for working at one well at the time. On production platforms with multiple wells it would be of interest to work on more than one well at the time. For example working on one well with drillpipe while working on another well with wireline or coiled tubing. Also the setting and retrieval of temporary plugs can be done faster while not compromising safety. While the primary load path on a jack-up is through the rotary table some operations do not really require the high lifting and lowering capacity which is offered by the topdrive assembly in the derrick. Especially for wireline and coiled tubing operations the lifting and lowering capacity can be much lower. So an add-on device with reduced load capacity which enables non-drillpipe operations can be advantageous. Especially when it can be working free of obstructions under the cantilever of the jack-up. The new add-on device will increase rig efficiency during development drilling, well workover/intervention and plug & abandonment operations. It for instance enables wireline guidance into the well through its moveable arm with the hoisting point below the cantilever. This while other operations on an adjacent well are executed simultaneously through the rotary table.

A combined offshore jacket structure and foundation concept is presented, which is installable from a jack-up drilling rig. This novel system integrates the various components with extensive track record in both the offshore oil & gas and windfarm industries. It is founded on suction buckets that use water underpressure to drive installation of the foundation. It is rapid and quiet to install and re-usable; utilising the same jack-up that will be drilling and/ or abandoning the wells to perform the installation/relocation. The scope of the paper is to present the technical aspects of installation, structural and foundation engineering necessary for successful development of such facilities. This includes consideration of interaction between the structure and jack-up during both installation, but also during operation (work-over) and re-use.

Shell Malaysia embarked on a Low-Cost Exploration and Development (LCD) journey to unlock previously stranded accumulations in the Central Luconia province. By leveraging on the long history of exploration and sub-surface data, a successful exploration campaign with Joint Venture (JV) partners yielded five field discoveries. The current Low-Cost Development strategy focuses on developing these fields with the JV partners through standardized lean well-head platform (WHP) tie-back to existing infrastructure. This paper describes the journey and the paradigm shifts within the company and its JV partners to achieve a WHP design that is low cost, light weight and replicable for future exploration discoveries. Front end loading work and competitive scoping is applied to establish minimum requirements for safety and operability resulting in barebones functionality with many functionalities removed or scope reduced. This includes evaluating novel technology application such as solar panels for power versus the conventional turbine generators. A key paradigm shift within the company is to challenge company standards and to reconcile the gap between company and industry standards. Company standards are prevalent in the oil and gas industry with standards differing for various operators. A key effort undertaken by the project team is to strip down the differences in company standards and requirements between the various JV partners and industrial standards. To capitalize on the market environment of low oil price, the project steers away from conventional segmented contracting strategy with an EpC approach with competitive bidding to leverage on contractor's capability to further bring down cost. The outcome of the competitive scoping and the focus on minimum functional requirement is a lean standardized WHP design, half the weight of recent WHP development projects without compromising safety and operability. The standardized WHP design is replicated for three fields within the same PSC resulting in reduced FEED engineering costs and shortened project cycle for future developments. CAPEX reduction is anticipated through leveraging on economy of scale for procurement of materials and equipment as a result of the replication of standardized WHP design. With this approach of standardized minimum requirement WHP, it allows for new strategy for future field explorations and development by focusing on clustered exploration around the vicinity of existing infrastructure allowing for stranded marginal accumulations to be developed.

After the successful delivery of two mammoth deep water projects in Sabah, Shell Malaysia turned its attention to develop cost competitive solutions to further develop and generate growth for small/marginal field development. The initial focus was to develop a low cost, minimal facility platform, which meets all the HSSE and operational requirements for a marginal gas field in Sarawak. To do things differently, new but proven technology had to be utilised and for this initial low-cost development wellhead platform, solar panels were employed to generate power for the platform facilities. Electricity generated by this technology is currently limited to 1200 Watts and due to this, the design of the controls of automation systems had to morph along with this limitation. Equipment such as pumps, control and safeguarding systems had to run on 24VDC supply. A low powered integrated control and safeguarding systems, limited to a power consumption of no more than 250 watts, suitable for installation and operation in outdoor hazardous environment, with temperatures reaching 50°C, had to be employed. Due to the power supply limitation, pressurised control rooms to house controls and safeguarding systems now are a thing of the past. And the design of the wellhead control panel was optimised by minimising the number of 24VDC pumps and utilizing pressure boosting regulators to achieve the different required pressures.

With soaring global demand, depleting supplies of crude oil coupled with the collapse in the oil prices, maximizing oil production in mature fields has become a priority. Such fields account for over 70% of the world's oil and gas production, with a worldwide average recovery factor of 35% for oil. Main challenge encountered by mature oil fields is the well pressure depletion over time. Since pressure depletion is inevitable, it is particularly challenging to continue to produce as there is insufficient reservoir pressure to push the well fluids to the main processing facilities. The system discussed in this paper is an effective engineering solution designed for topside receiving facilities. The Low Pressure Production Unit ‘LPPU’ is a separation system for boosting the pressure of production fluids from low pressure wells. It is ideally suited for remote wellhead platforms where wells have insufficient pressure to deliver well fluids to production header, space is a constraint, and manning is not required. Conceptual design of this system is based on the very low, almost atmospheric, operating pressure of the system, wherein the flow from the well to topside becomes easier without the need to inject the well itself with any foreign elements. The system is designed in such a way that it can receive continuous full flow from the well, and still manages –through intricate isolation methodology- to operate in batches. This batch operation arrangement allows for liquid accumulation which is then discharged to the production header after being pressurized. System adopts different variations based on availability; it either uses HP gas -typically from existing gas-lift compressor from the main processing platform- or compresses the associated gas from the FWS to be used as ‘motive gas’ which is used to pressurize and push down the accumulated liquid towards the delivery of flow to the production header. A characteristic optimization factor that contributes greatly to the economic and operational attraction of this system is its ability to utilize its equipment to combine solutions for the two challenges of 1-reduced pressure that's beneficial to the well flow, and 2-the higher pressure essential for the production header.

This paper proposes a work flow to address the challenges of over pressure in pipelines using the industry standard multiphase transient simulator. Electric submersible pumps (ESPs) are commonly used to increase the productivity of the wells, which, in turn, will generate higher shutoff pressure in the event of sudden wellhead and subsea line valve closures. The topside piping or the subsea line must be protected from overpressure during valve closures with the ESP still in running condition, so that the pressure does not reach beyond the maximum allowable operating pressure (MAOP) of the pipeline. Hence, it is critical to estimate the peak pressure surge, time to reach peak pressure, emergency shutdown (ESD) set point, and high-integrity pressure-protection system (HIPPS) initiation time. The topside piping is normally designed with an MAOP significantly lower than the ESP shutoff pressure. In the event of sudden closure of wellhead platform valves or the valves located at the end of a subsea pipeline, the pipeline will be pressurized equivalent to the shutoff pressure of the ESP. In general, to protect the topside piping, several layers of protection are provided, with ESD and HIPPS being very common. The proposed workflow demonstrates the use of a multiphase transient simulator to estimate the peak pressure reached upon wellhead valve closure and the time required to reach the peak pressure for different scenarios so that the ESD initiation set point can be selected optimally. Once the ESD sequence activates, the pressure response in the piping during shutdown also can be estimated in an accurate manner. Further, in case the ESD system fails to respond, the workflow identifies the time to activate the HIPPS system, which will be based on the MAOP and time needed for HIPPS to activate. The workflow has been used extensively in major oil projects with ESP-operated wells to address their ESD and HIPPS activation set-point selection as a part of HAZOP closeout. The workflow underscores the role of transient simulations in predicting the peak pressures, timing, and optimal ESD and HIPPS activation time to protect wellhead piping, thereby providing critical information to address piping/pipeline integrity challenges.

One of the methodologies for developing deep water oil and/or gas fields may call for the use of a Tension Leg Well head Platform (TLWP). The TLWP supports the well heads above the water line and allows for drilling and well intervention. The TLWP is assisted by a Tender Assisted Drill rig (TAD) that provides many of the drilling services. The presented TLWP is intended for use in the more benign areas in the world, i.e. non-hurricane / non-cyclonic regions. The design of the TLWP includes a variation of the balance of the typical design parameters which leads to overall improvement of satisfying the various requirements. One of the design parameter which is addressed is a simplified marine system combined with a hull and pontoon framing methodology. The objective is to make the hull as passive as possible, i.e. minimal human activities required inside the hull. A second design parameter addressed is a hull form where the displacement can be changed with reduced impact on the major structural elements. The objective is to minimize the impact on construction if there are significant weight changes late in the project, typically weight growth. A third design parameter is a deck layout which allows the drill riser to travel fully deployed across the entire well bay. The objective is to facilitate and speed up the drilling program.