Indonesia has become a net-oil importer since 2004 as the growing internal demand exceeds Indonesia's oil production. As many fields go into mature phase and combined with other challenges, the national oil production in the last decade has been decreasing from 945 MBOPD to 745 MBOPD with a decline rate of 3-5% per year. Thus, the contribution of the oil and gas sector to the state revenues has also shown a downward trend from 21% in 2010 to only 9.2% in 2019. However,oil production is still strategically importantfor the national economy. It is important for economic value creation, power generation, transportation, and industries as most of the archipelago's infrastructures are still based on fossil energy. If no effort is made to increase production, the country will be fullydependent on crude oil imports, which poses a threat to national energy security. It is thereforeinthe nation's great interest to enhance oil production, minimizing the deficit gapbetween export and import. Several key strategies may be considered to achieve this ambitious target. These strategies can be categorized into the following: 1) People and high performing organization; 2) Exploration, as critical factor for future production; 3) Improved oil recovery (including enhancedoil recovery) technologies, to grow production from the maturing fields; 4) Fast track and simplified project to develop small field discoveries; 5) Strong collaboration between government, industry, academia, and professional associations; and 6)Cost conscious culture. The derivatives of the above-mentioned strategies are among others: standardized resource data management, open source & digitalized geoscience data library, reimbursement system for exploration costs, near field/infrastructure exploration,new play concept, cluster license collaboration, infill wells campaign, multilateral wells, waterflooding, gas injection, stimulation and hydraulic fracturing campaign, well interventions, EOR screening, perfect-well optimization, standardize subsea and/or topside production system, digitalization, and attractive fiscal and regulation that encourages not only the ‘big operator’ to participate in the petroleum sector. The foundation of these strategies should be the legal certainty and effective & proactive bureaucracy. Above all, it is also important to emphasize the common ground of havingearly HSE involvement as part of the solution. In this paper, the authors would like to contribute in sharing the knowledge, technology and perspectives to all petroleum industry professionals in Indonesia based on the authors exposure in the Norwegian petroleum activities. The paper will also review the strategies, short term and long-term opportunities that may inspire Indonesian petroleum authorities and industry in transforming the ambition into action to achieve the national production target of 1 MMBOPD and 12 BCFD gas by 2030.

As an oilfield goes mature, an increased water cut can significantly decrease the maximum fluid production rate or even stop the production entirely. Therefore, separating produced water from the wellstream as early as possible is a potential way to maximize oil production. A novel inclined gravity downhole oil-water separator concept has been introduced and patented by ABB Research Ltd., which combines gravitational separation with distributed water tapping along the incline separator tube. The concept depicts that the downhole separator can be installed somewhere above the production packer and below SCSSV (surface-controlled subsurface safety valve). Gravitational forces create a separated water or water rich layer at the lower side of the pipe. This segregated water rich layer is drained using distributed tapping points along the separation tube and then flow to surface via annulus, whilst the oil rich layer flow through the tubing continue up to surface. Several experimental tests have been performed and this paper describes how to use the experimental results into a well performance simulator to predict how the inclined gravity downhole oil-water separator modifies the performance of high production rate wells. The study includes the well performance effect of separator setting depth, setting inclination, tubing size and tubing configuration. Well performance sensitivity due to water cut and separation efficiency is also discussed. The simulation results show that inclined downhole oil-water separation is very beneficial and able to increase oil production up to 82% for the selected wells with 81–87% water cut. Introduction Conventionally, oil and water are separated at the surface using gravity-driven separators, where the size of the separator is a function of flow rate and the required retention time. The gravity separators often occupy large portions of the space on the offshore platform. In the mid 80's hydrocyclones and centrifuges have been introduced to treat produced water before disposal. Around the 90's, tests of separation facilities with hydrocyclones as a bulk separator has been carried out successfully. These technologies have directed the industry towards the size reduction of separation facilities at surface. However, a major further step is to separate the bulk of the water in a downhole in-line arrangement 15. Applying downhole oil-water separation (hereafter, called as DOWS) could de-bottleneck the production plant on platform and reduce the space on board, eliminate future need of new constructions to increase water handling capacity. By separating water in the downhole, the liquid density of the wellstream and the back pressure on the formation are reduced. Hence, increasing the drawdown pressure which enhances production (Fig. 1). Three basic types of downhole oil water separator have been classified based on the separation system utilized6. The first type using hydrocyclones, the second based on gravity forces and the third type using membrane separation technology, which is yet to be developed and applied in the field but has been investigated through simulation studies. A new concept in the gravity type separation is inclined gravity downhole oil-water separator with distributed water tapping where the drained water can be controlled effectively. Some advantages of this type of downhole separator are its simplicity, robustness in structure and the little sensitivity to the accuracy of installation angle. Due to its simplicity components, it also has a long-life potential. In the case where the separator fails to perform well it can be kept and used as ordinary tubing without the need of workover cost to pull it out. Some of the challenges to this concept are the design of the instrumentation that can regulate the drainage rate to achieve the best separation and the potential well integrity issue with regards to flowing HC in the A-annulus.

Several improvements on fluids, equipment, completion design and practices have been successfully implemented in the first subsea well of Morvin HPHT field offshore Norwegian Continental Shelf. These improvements are:Using new heavy weight reduced solid oil-based completion fluid for running the lower completion (predrilled liner) and achieving the expected initial productivity ;Extra well cleaning prior to running the lower and upper completion;A designed predrilled liner combined with open hole swell packers for zonal isolation and HPHT tracer-subs for data acquisition;Downhole barrier being installed as an integral part of the lower completion, eliminating the middle completion ;New HPHT permanentretrievable production packer; andSuccessful installation of downhole P/T gauge with pig tail connection below the tubing hanger. Completion operation on the first well was completed in 40 days (i.e. 12 days less than the planned days) with no major operational set back, safety and environmental incidents. After the well clean up, the well has been flow-tested up to 1500 Sm3/d (limited by rig capacity) and the well testing evaluation shows that the well delivers productivity as expected. Tracer samples analyses also show good production contribution from both reservoirs being penetrated by 1000 m of 8-½?? horizontal hole section. The HPHT reservoir (819 bar / 162 oC) in Morvin wells requires a different approach to completion design and practices in order to avoid well control incidents, operational problems, and achieve full well integrity during its production lifecycle. It demands the use of non conventional materials and fluids, careful equipment selection which is seldom available off-the-shelf in today's market, equipment qualifications and new procedures1. This paper describes the original completion concept that was much influenced by well completion experiences from the Kristin field, the world's first HPHT field to be developed subsea from multi-well templates. The paper then discusses the improvements made from the original completion design, challenges and contingencies. Introduction Today, oil and gas E&P activities have been steadily expanded into handling more complex and challenging projects such as high pressure high temperature (HPHT) wells. Among the regulatory bodies, the Norwegian Petroleum Directorate (NPD) defines HPHT wells as deeper than 4000 mTVD and/or having an expected shut-in wellhead pressure (SIWHP) exceeding 690 bar and/or having a bottom hole temperature exceeding 150 oC2. The main factors affecting the completion design and well integrity in HPHT wells are the extreme surface pressure, very high temperature, and various load scenarios during their lifecycle combined with the corrosivity level of the well environment. Risk of failures in this HPHT completion design is usually associated with2:High stress environment, both tension and compression.High operating temperatures.Chemical activity of well fluid components enhanced by the high temperature.Narrow margin between the boundaries of load uncertainties and equipment's material rating. Longer planning process is sometimes required to anticipate long lead times of HPHT specific equipment. Longer time is also needed for the equipment qualification.

Drilling the lower overburden section in specific parts of the Greater Ekofisk Area (GEA) fields can be very troublesome. Wells in these parts may intersect shales with high gas content in the upper section (requiring high mud weight) and unstable zones with massive lost circulation risk (requiring low mud weight) near the base of the interval. These challenges have raised the need for a contingency drilling liner to "split" the section in two parts. Rather than changing the basic well design, the operator fronted the development of an 8-5/8″ expandable drilling liner with high collapse resistance for this purpose. This string provides 8.514″ post-expansion drift ID that accommodate an 8 ½″ bit size for the reservoir section, which is critical for GEA well design strategy. In the past five years, the operator has successfully installed 31 800 ft of 8-5/8″ expandable liner in 27 different wellbores with near perfect track record. The average liner length installed is 1 140 ft per wellbore, with an average installation time of 2.8 rig days. The solid expandable tubular (SET) drilling liner has been utilized both as part of the planned well design and as contingency liner. It has, on occasions, been worked down with parameters outside the stated specifications and still been successfully expanded afterwards. The 8-5/8″ expandable liner is now a proven system and has been one of the key enablers to achieve well objectives by maintaining hole size in a predictable manner. It provides a better drilling window for reservoir drilling and reservoir liner cementing compared to a conventional 7-3/4″ liner alternative. It also enables further contingency solutions in case other difficulties arise in the reservoir section. This technical paper describes how the operator in the overcame a significant geological challenge by working with an expandable pipe supplier to develop a unique size and strength of expandable liner that fits with the base case GEA well design. The paper also reviews the installation experiences, associated risks, performance, and key learnings with expandable liners.