This course discusses the fundamental sand control considerations involved in completing a well and introduces the various sand control techniques commonly used across the industry, including standalone screens, gravel packs, high rate water packs and frac-packs. It requires only a basic understanding of oilfield operations and is intended for drilling, completion and production personnel with some sand control experience who are looking to gain a better understanding of each technique’s advantages, limitations and application window for use in their upcoming completions.
PETRONAS FLNG SATU (PFLNG1) is a floating liquefied natural gas facility producing 1.2 million tonnes per annum (mtpa) of LNG, on a facility that is 365m long, and 60m wide, making it among the largest offshore facility ever built. The PFLNG1 project is the first of its kind in the world and is the first deployment of PETRONASâ€™ Floating Liquefied Natural Gas (FLNG) technology, consolidating the traditional offshore to onshore LNG infrastructure into a single facility. This will see a giant floating facility capable of extracting, liquefying and storing LNG at sea, before it is exported to customers around the globe. The FLNG journey has come a long way since 2006, with many technological options explored to monetise and unlock the potential of small and stranded gas fields. Moving an LNG production to an offshore setting poses a demanding set of challenges â€“ as every element of a conventional LNG facility needs to fit into an area roughly one quarter the size in the open seas whilst maintaining safety and increased flexibility to LNG production and delivery. The keynote address describes the breakthrough features of PFLNG1 â€“ the worldâ€™s first floating LNG facility; and the pioneering innovation that it brings to the LNG industry.
SpillRisk oilfield lies in Cepu block, East Java Sea, Indonesia. Oil production recently commenced from the promising field and shipping is done through a floating storage and offloading (FSO) vessel. In consideration of the environmental sensitivity of the area, with its rich marine and terrestrial biodiversity, the prevention of pollution or at least readiness for prompt combating of possible oil spills from operations becomes a major concern for both the Indonesian government and operators. This study thus undertook the deployment of two models - GNOME and ADIOS - to forecast the likely trajectory and fate of oil on water should there be a spill during discharge from the FSO into loading tankers. Key environmental data on both baseline and predicted changes in conditions were built into both models. A minimum regret option of 10% was built into the GNOME models to account for uncertainties of forecasting and possible errors in field data acquisition. Results of the models were critically analysed, matching them against published literature on similar concessions within the same geographical area, in order to guide spill responders on the best options. It was found that emulsions form more readily during winter due to the higher viscosity of the oil coupled with the high presence of sediments in the coastal area. The oil was predicted to beach after 4 days of release, thus posing grave dangers to the shoreline ecosystem. Response efforts would thus be effective within the first 24 hours of the spill start time.
Suggestions for improving the outputs obtainable from GNOME and ADIOS were made after calibrating the results with those from an earlier commissioned study that had used the OILMAP software for the same field. The recommendations that follow would serve as a reference for the preparation and amendment of oil spill contingency plans for the area, as well as a guide for surrounding and similar hydrocarbon producing assets in Asia.
The Banyu Urip field has been producing crude oil since 2009. The initial development used a temporary Early Production Facilities (EPF) with 20,000 BPD capacity. The EPF was retired in late 2015 followed by the start-up of the permanent Central Processing Facilities (CPF). The CPF is designed to handle 185,000 BPD of crude oil. Soon after the CPF start-up, efforts to increase production capacity beyond 200,000 BPD were initiated.
This paper will share the Banyu Urip process to increase production capacity with minimal incremental investment. The Banyu Urip production optimization effort focused on two aspects – engineering studies to identify the limitations of the existing facilities (modelling as-built conditions from inlet facilities to the sales point at higher rates using a multi-disciplinary approach) and field tests to validate simulation results and identify required facility modifications.
One of the key foundations for facility bottleneck identification was a field high rate test. The field test indicated that the facility was able to sustain higher rates, however it was constrained by warmer crude oil exceeding export temperature limits. This challenge was overcame by utilizing an existing facility, initially intended for crude desalting, instead being leveraged to deliver ambient temperature deaerated water and mixing with hot crude streams to provide sufficient cooling and reduce heat exchanger duty.
Banyu Urip field continues to deliver a significant portion of Indonesia's oil production by maintaining a high level production efficiency. The field continues to see strong production from the oil wells and the plant has a proven capability to produce up to 220,000 BPD. The capability to increase production was achieved in less than a year after start-up and used a cost efficient approach from the beginning. The crude oil export temperature is managed by creatively leveraging existing facilities.
Recently in Indonesia are experiencing various of revision and improvement in the regulations, related with the oil and gas industry activity, this kind of situation certainly will impact to the investment atmosphere in the Indonesia oil and gas upstream. International Oil Company and the Government has different point of view related to contracts in PSC. Several analysis or study has been done by institutions and individuals through articles or papers on the comparing for the terms and conditions of a contract with different country. But not many have discussed particularly about the general change of PSC in Indonesia.
This study will compare the historical of Indonesia PSC generations from generation I (1966) until the recent fiscal terms of gross split (2017). Those terms will be compare by using a hypothetical block to modelize the PSC block in Indonesia, which consist of several field. Some assumption also will be used for each field with different peak rate, development scenario, capital variable cost ranges, operation variable cost ranges, which those range data are expected still within the range of most likely consist parameter for PSC block in Indonesia.
This study purpose is to analyze if the Gross Split mechanism is more attractive or equal the PSC Cost Recovery. The result of this study shown that the gross split PSC refer to the Minister of Energy and Mineral Resources no.52 year 2017 is still attractive to the investor from the contractor take perspective. Eventough with the PSC Cost Recovery mechanism the contractor feels more secure for the cost that can be recover from the oil and gas that produces, as part of cost recovery. If the application of Gross Split is clear enough from the regulation, tax, assets rent and others, surely this mechanism can attract more investor to do exploration and development in Indonesia.
Regardless of the political and strategic interests of the Indonesia government or the National Oil Company, the results of this study hopefully can be useful for the professional, educational institution, and government for lesson and learn. How the fiscal term can be impact to the government take, contractor take, cost recovery also the production target related with reserves replacement.
Banyu Urip crude contains 26% wax which can provide flow assurance (FA) challenges in a stabilized crude pipeline exposed to lower temperatures. Injection of Pour Point Depressant (PPD) chemicals has widely been considered as an effective method to ensure flow assurance for moderate waxy crude. For the Banyu Urip field in Indonesia, PPD injection was compared to other methods and found to be the best option from a cost and operability perspective. Nevertheless, it still contributes to almost 20% of Banyu Urip operating costs. Optimization of this chemical usage brings benefit both for the Operator and also for the government through lowering operating costs.
In the past, the flow assurance of waxy crude was determined by measuring \Pour Point (PP) temperature. At temperatures below this PP, the crude will stop flowing. PP measurement has several limitations, including providing a lower representation of the actual conditions. In this paper, a restart pressure simulation model and pilot experiments were used to provide a more realistic condition assessment and helped to avoid over-injection of PPD.
In the enhanced gel strength concept, a weak waxy crude gel may be formed in the pipeline below its PP and still be breakable by applying pressure within the pipeline's Maximum Allowable Working Pressure (MAWP). Furthermore, the size of pipeline and the wax's natural insulation capability provides a radial temperature profile which can prevent the core pipeline from seeing a rapid temperature reduction. A pilot experiment for establishing a radial temperature profile has been conducted in by the Operator leveraging local university support. The same approach will be conducted for an upcoming flow loop experiment for restart pressure validation.
In Banyu Urip, the initial PP target was set at 24°C based on the lowest seabed temperature observed in the offshore section of the pipeline. This target resulted in a PPD injection dosage of ~500 ppm. Using the enhanced gel strength concept, the required PPD injection rate was reduced to ~300 ppm. Further reduction is expected after conclusion of the radial temperature profile and flow loop experiments.
Banyu Urip Field is located in Central-East Java, Indonesia where well production fluids are routed from wellheads to processing facilities via interconnected full well stream piping and flowlines. The produced fluids contains high level of CO2 (45% mol) and H2S (1.5% mol). The utilization of carbon steel in the design of piping and equipment makes them susceptible to corrosion. Injection of corrosion inhibitor (CI) is recommended to minimize material degradation, and correct selection of CI is key to ensure corrosion management is effective and efficient.
A comprehensive understanding of produced fluid properties is important prior to CI selection. Various experiments were conducted in high pressure-high temperature Hastelloy autoclaves to simulate process conditions, with support from proprietary company software modeling 7%, 20% and 80% water partitioning in Banyu Urip Oil samples. An oil-water wettability study was also a key factor to predict the threshold water cut at which produced water separates from crude oil and wets the metal surface of the flowlines.
The experiments revealed potential corrosion rates that could be expected in Banyu Urip flowlines for a range of production scenarios. Results also demonstrated that a decrease in liquid shear stress yields a decrease in corrosion rate; where as a decrease in temperature yields an increase in corrosion rate due to reduction of FeCO3 scale protection. This FeCO3 scale protection provides self-inhibiting properties which are keys to selection and optimization of CI.
Through the oil-water wettability study we can determine an optimal time where the metal surface is wetted by water and thus requires CI to control corrosion. This will help in determining the most cost effective corrosion management programs for the facilities.
This paper will provide an overview of the Banyu Urip corrosion inhibitor selection process; describe the corrosion experiments conducted to verify the crude properties and the oil-water wettability studies to optimize the injection of CI.
Recent discussions and publications in the oil and gas industry (
This paper provides background on initial workforce performance and behaviors, the introduction and continuous coaching and mentoring of CRM PBE-AAR, and the results achieved. EMCL-Drilling concluded over 20-rig months of operations with CRM PBE-AAR, with notable obstacles of language barriers and arduous rig moves in difficult terrain, where rigsite personnel and supervisors were assessed, human behaviors modified, and process controls improved with zero hurts, zero spills, and significant improvement in operational performance efficiency. As a result of workforce improvements and empowerment, new tools and technology were introduced to further ingrain learnings and capabilities. Rigsite teams demonstrated increased professional and personal pride in their work, taking ownership of processes, accepting responsibility and accountability for their actions and the actions of others, and most importantly developed a sense of empowerment knowing their voices and opinions were heard, respected, and acted upon. The culmination of these efforts resulted in EMCL-Drilling completing the final phase of its Banyu Urip drilling campaign completely hurt free, spill free, and with a perfect day efficiency of 95%.
Banyu Urip Field is a newly developed oil reservoir located in between Central and East Java provinces, Indonesia. The field is currently producing in an early development phase. There are 4 producer wells, 1 gas injector and 1 water injector. The six wells are located on one well pad and production flows to temporary facilities operated by another party.
Two years after starting production, inflow capacity began to rapidly deteriorate in one of the producers; resulting in a decline in overall field deliverability. The declining well is a deviated well which had experienced massive lost circulation while being drilled. The well initially produced at the highest rate among the 4 producers. However after the rapid production decline it produced at the lowest rate of the four producers.
This paper describes steps taken in evaluating the root causes of the decline in well productivity. Research and screening mitigation options are also discussed in this paper. Lost circulation materials, plugging, and scale/wax build-up are suspected as potential root causes of the decline in productivity. Acid stimulation, coiled-tubing cleanup, and re-perforating were identified as possible mitigations. The workover was divided into 2 phases; phase-1 was conducted for data acquisition and phase-2 for execution. Furthermore, this paper continues with describing the well work execution and challenges.