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The XamXung field offshore Sarawak, Malaysia, is a 47-year brownfield with thin remaining oil rims that have made field management challenging. The dynamic oil-rim movement has been a key subsurface uncertainty, particularly with the commencing of a redevelopment project. Energy consultancy Wood Mackenzie estimates the find holds some 2 Tcf of gas, making it this year’s seventh-largest discovery worldwide. The state-owned firm is looking within its home country, around Southeast Asia, and to the Americas—including shale—in an effort to maintain its forecast average yearly production of 1.7 million BOE/D over the next 5 years. Malaysia’s Petronas, Shell Malaysia, and Thailand’s PTTEP are now in the midst of full-scale digital adoption.
Sand-control-installation failures range from minor issues that can be remedied easily to catastrophic events that put the entire well and investment at risk. As operators feel the pinch of low oil prices, so, too, do their service providers. This paper discusses a probabilistic flux and erosion model and work flow that extend the ability to estimate inflow through sand screens on a foot-by-foot basis along the wellbore using the well's completion details, production rate, and reservoir and bottomhole flowing pressures. Analytics, sensors, and robots are changing the way one of the world’s largest oil and gas companies does business. Underpinning all the new technology though is a shift in how BP thinks, and what it means to be a supermajor in the 21st century.
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.
Since the industrial revolution, the oil and gas industry has played an important role in the economic transformation of the world, fueling the need for heat, light and mobility of the world’s population. Today, the oil and gas industry has the opportunity to redefine its boundaries through digitalisation, after a period of falling crude prices disrupted exploration and production activities, and ineffective mature field development challenges that are currently facing most oil and gas companies in Indonesia. The recent downturn in the oil and gas industry has led to massive layoffs. Digital industrial revolution is slowly changing how upstream businesses operate. Increasing public awareness of climate change has fuelled the urgency to shift to cleaner alternative energy. Can the current petroleum engineers survive in the next 10 to20 years?
This article presents brief summaries of detailed petrophysical evaluations of several fields that have been described in the SPE and Soc. of Professional Well Log Analysts (SPWLA) technical literature. These case studies cover some of the complications that occur when making net-pay, porosity, and water saturation (Sw) calculations. Prudhoe Bay is the largest oil and gas field in North America with more than 20 billion bbl of original oil in place (OOIP) and an overlying 30 Tscf gas cap. In the early 1980s, the unit operating agreement required that a final equity determination be undertaken. In the course of this determination, an extensive field coring program was conducted, which resulted in more than 25 oil-based mud (OBM) cores being cut in all areas of the field and some conventional water-based mud (WBM) and bland-mud cores in other wells.
The design of an invert emulsion fluid that can hold up more than 24,000 psi and 435°F is a complicated and exhausting process. The challenges presented in the design of an UHPHT drilling fluid formulation are the base oil selection and the complete drilling fluid formulation. Flash point measurement of base oil before and after heat ageing to ensure that the base fluid were stable and the overall stability of the mud system need to be assured (rheology, gelation, fluid loss and weight material suspension) after both dynamic and static ageing for at least 96 hours at anticipated maximum BHST.
Laboratory pilot testing allows us to find a chemical balance where the rheology profile and mud properties fulfill the UHPHT project requirements. The laboratory testing protocol validation is the most important factor to prevent different issues during the drilling phase. This testing will be a contributor factor to conclude a well successfully.
Another phase of the design that we need to consider is an exact dynamic temperature modelling because a more precise Bottom Hole Temperature profile helps optimize the drilling process to increase the possibility of borehole stability.
Mokogwu, Ike (Scaled Solutions Limited) | Hammonds, Paul (Scaled Solutions Limited) | Wilson, Sam Clare (Scaled Solutions Limited) | Healy, Caitlin (Scaled Solutions Limited) | Sheach, Ewan (Scaled Solutions Limited)
Near-wellbore clay fines migration presents a formation damage risk in many gas wells. Fines mobilization can occur due to weakened electrostatic forces on ion exchange with an introduced fluid making them more prone to movement by viscous drag, or where the drag forces are sufficient to physically break or lift clay crystals from their original location, and distribute them throughout the pore network. Fines migration potential is typically assessed
Reservoir core is often scarce or unavailable, which means that it can be difficult to evaluate different core flood test protocols and fluids. Outcrop samples provide a convenient alternative as they are readily available and cheap to acquire. This paper describes the first phase of a research program that aims to identify outcrop sandstones that are prone to fines migration as a result of drag forces on gas flow, and to evaluate different test protocols.
Coreflood tests were carried out on clay rich (predominantly kaolinite) Blaxter sandstone, with samples having a typical permeability of approximately 30-40mD. Potential permeability impairment from fines migration was assessed by sequential and incremental critical velocity tests at both low (290 psig) and high (1450 psig) pressure conditions, and at gas rates of up to 2 L/min. Tests were performed with nitrogen (OFN), and gaseous and supercritical carbon dioxide. In addition, hydrocarbon gas analogues (hexane and dodecane) were also evaluated as a substitute for dense gases in coreflood testing.
Initial critical rate tests using KCl brine showed the potential for salinity-related permeability damage in Blaxter sandstone cores, demonstrating that these cores are susceptible to fines migration. However, test results using anhydrous gas demonstrated that pressure and flow rate variation in the laboratory had no notable fines migration effect on the Blaxter sandstone samples. In addition, the use of different hydrocarbon gas analogues showed that even when the test fluid density is selected to so that it is similar to a liquid - supercritical CO2, or light hydrocarbons such as hexane and dodecane - fines migration is still absent even at high flow rates.
The outcrop core test results do not necessarily indicate the absence of fines migration potential in gas wells. The kaolinite fines in Blaxter sandstone may not display the well-developed clay crystal structures and morphologies normally associated with reservoir sands, and which may expose the clays to higher drag forces. The case studies presented here will aid in improving coreflood test protocols for assessing formation damage in gas wells. This improved understanding will ultimately enhance the application of core flooding as a tool for identifying formation damage in gas wells.
M. Ibrahim, Jamal Mohamad (Petroliam Nasional Berhad, PETRONAS) | Mat Piah, Mohamad Faizzudin (Petroliam Nasional Berhad, PETRONAS) | Panuganti, Sai Ravindra (Petroliam Nasional Berhad, PETRONAS) | Salleh, Intan Khalida (Petroliam Nasional Berhad, PETRONAS) | O. Hussein, Adil Mohamed (Petroliam Nasional Berhad, PETRONAS)
Almost all Malaysian hydrocarbon-bearing sandstone reservoirs contain minerals which are potential sources of mobile fine particles. For this reason, formation damage in injection and production wells has been frequently associated with the migration of fines in reservoir pores. In this work, an effective, novel, environment friendly and cost beneficial fines stabilizer is formulated in-house.
The developed chemical works on the principles of coagulation and flocculation. Different coagulant and flocculant chemical combinations are trialed, and the understanding of their performance is shared using turbidity and zeta potential testing. The developed fines stabilizer chemical is later tested for compatibility with reservoir fluids and production chemicals of a field which is planning to apply fines stabilizer. Based on the potentiality in static screening results of turbidity, zeta potential and compatibility, a fines stabilizer is chosen for dynamic testing.
The constraint of critical flow rate for fines migration is addressed in dynamic study using core flood experimentation. Critical flow rates are determined by forward and reverse injection into core samples. Accordingly, the performance of in-house synthesized fines stabilizer is judged by enhancement in critical flow rate in comparison to untreated and commercial fines stabilizer treated cores. Since the constraint from the critical rate effects injectivity and productivity, modification of this constraint and increase of the critical rate consequently provides more economic benefit. The additional revenue from oil production by using the in-house developed fines stabilizer chemical is estimated, and the costs are compared with a commercial fines stabilizer.
The uniqueness of this endeavor is in developing an in-house fines stabilizer chemical which can be used after acidizing, enhanced oil recovery treatment, in production and injection wells. The synthesized in-house formulation is more effective and cost saving compared to commercial fines stabilizer.
Costam, Ronald Yusef (CPOC) | Xiannan, Wang (CNOOC) | Fadjarijanto, Ari (CPOC) | Daungkaew, Saifon (Schlumberger) | Gao, Bei (Schlumberger) | Duangprasert, Tanabordee (Schlumberger) | Edmundson, Simon (Schlumberger) | Perrin, Cedric (Schlumberger) | Airey, Peter (Schlumberger) | Andic, Hikmet (Schlumberger) | Hoong, Tan Yinn (Schlumberger) | Khunaworawet, Tanawut (Schlumberger) | Shichao, Lin (Schlumberger) | Wei, Zhang (Schlumberger) | Chen, Jichao (Schlumberger) | Tao, Zhang (Schlumberger) | Phanatamporn, Kitithorn (Schlumberger)
As oil and gas exploration and production extends to deeper buried reservoirs, challenges such as lower porosities and Ultra High Temperature have been encountered. Several reservoirs in the Asian region, the North Malay basins in the joint development area between Thailand and Malaysia, and the Baiyun Sag and Qiong Dongnan basin in offshore China are considered to have the highest known temperature gradients due to their geological depositional system and hydrocarbon charging mechanism. More than fifty percent of wells drilled in these areas have temperature close to/or higher than 170 degC, and some reach above 200 degC. In number a of projects in these areas, the logging requires tools that can withstand up to 230 degC.
Traditional, wireline Formation Testers (FT) with fixed rate and volume pre-test and old sampling technique using a dumping chamber (i.e. without pumping capability) had been the standard formation tester when temperatures reached 400degF (204 degC) and higher. The tools were not flasked and therefore, the temperature transient affected the quality and accuracy of pressure data
This paper discusses a project for a new slim hole ultrahigh temperature Wireline Formation Tester designed to obtain both pressure profiles and perform downhole Pressure Volume Temperature (PVT) *Trademark of Schlumberger fluid sampling with pump-out capability and downhole fluid sensors such as viscosity, density and resistivity in extreme HT environments. In addition, this slim hole ultrahigh temperature tool dimension has more clearance between the tool and formation, and therefore, less chance of having this tool get stuck during slim hole logging.
The tool was first deployed in the North Malay Basin and since early 2018, new well head platform with five development wells were logged where a total of 76 pre-tests, four pump-out and ten fluid sampling stations were conducted. The main objectives for this FT tool were to obtain formation pressure, identify reservoir fluid and quantitative CO2 measurements zone by zone. The results will be discussed operationally and technically, in terms of data quality and accuracy and compared with on-site surface analysis. In addition, this tool improves significantly operationally compared to the previous tools and with some operators having mixed perceptions on running Wireline FT tool with bigger ODs, especially drilling departments, having this new slim hole with its smaller OD increases their confidence level in running it.
For Deepwater Offshore China, an operator has been facing challenges to explore a brand-new block such as pore pressure distributions profile, reservoir quality, and extended logging period. The main objectives for the extreme FT are to obtain the formation pressure for drilling purpose, to understand reservoir potential to optimize the perforation interval for Drill Stem Test, and to narrow logging operation time window due to seasonal weather. This new ultra-high slim hole was therefore proposed to log in this challenging environment. This field example shows a significantly improved pre-test and sampling capability in the lower mobility ranges, which some previous generations of formation testers had struggled with in the past, in one run and without sacrificing testing efficiency The effective time for valid pretest can be achieved even in the range of mobility 0.01 mD/cp, high pressure of > 11000 psi, and high temperature of >180 degC.
This paper discusses pre-job planning and actual job execution results in both locations. The challenges of logging and lesson learned are addressed. This is the first attempt in evaluating reservoirs in the deeper and HT sections to properly understand reservoir fluids.
Tertiary shoreface-deltaic sediments in Brunei fields show different boomerang motifs on neutron-density and gamma ray-resistivity crossplots. A boomerang workflow named after the motifs is tested by calibrating to core data to quantify net/gross ratio and porosities under variable shale and hydrocarbon effects. The inflection between the two boomerang limbs marks the boundary between shoreface sandstones and offshore shale-type lithologies. Compared with subjective Vsh cutoffs, boomerang inflections are more objectively defendable signatures defining net and non-net rocks. Thin beds and heterolithic sandstones in lower shoreface and tidal environments are mixed in the sandstone limb near boomerang inflection. By including the thin beds and heterolithic reservoirs that are cut off by the Vsh approach, the static hydrocarbon in place in the studied fields increases by 10 to 40% based on the well data.
The shale matrix effect on porosity estimation in shaly heterolithic sandstones is resolved by interactively derived shale-line slopes without involving the uncertain clay volumes or clay parameters. Particularly, effective porosity, ϕEF, is estimated by inputting a wet-shale-line slope, ksh,, based on the shale limb on the neutron-density crossplot in each boomerang interval; it changes with depth as result of different compactions. Total porosity, ϕTOT, is estimated by a dry-shale-line slope; it is constant for most of the reservoirs based on core calibrations in the studied fields due to identical sediment provenance.
Hydrocarbon effect is independent of shale matrix effect, although they are mixed in the log responses. Hydrocarbon effect is qualitatively analyzed based on the angular rotation of the hydrocarbon-bearing sandstone limbs towards different fluid points. It is also quantitatively evaluated by the apparent fluid neutron-density parameters (φfl, ρfl) interactively determined by coherent ϕEF and ϕTOT estimations in a dual-porosity and dual-fluid model. For example, the calculated ϕTOT is significantly less than ϕEF if water parameters are used for gas-charged sandstones. By decreasing the (φfl, ρfl) from water (1, 1) until (ϕTOT – ϕEF) ≥ 0, we find the resultant ϕTOT matches with core porosity (except in unresolved thin beds); this is tested in more than 1,000 meters of cores in several fields covering a large range of lithology and hydrocarbon types. If invasion is insignificant, the resultant fluid density, ρfl, also matches with produced hydrocarbons. Therefore, the workflow not only provides coherent ϕEF and ϕTOT estimation in the rocks with variable shale and hydrocarbon effects but also the apparent fluid density profiles for hydrocarbon typing.