Toempromraj, Wararit (PTTEP) | Sangvaree, Thakerngchai (PTTEP) | Rattanarujikorn, Yudthanan (PTTEP) | Pahonpate, Chartchai (PTTEP) | Karantharath, Radhakrishnan (TGT Oilfield Services) | Aslanyan, Irina (TGT Oilfield Services) | Minakhmetova, Roza (TGT Oilfield Services) | Sungatullin, Lenar (TGT Oilfield Services)
Success towards waterflood optimization requires the accessibility of downhole contribution and injection, challenging on the conventional cased-hole multi-zone completion where contribution and injection are gathering through sliding sleeve. This paper will describe the success in defining flow profile behind tubing by utilizing Temperature and Spectral Noise Logging.
With response in frequency and noise power when fluid flowing through completion accessories, perforation tunnels and porous media, fluid entry points for producer and water departure point can be located by noise logging. Additionally, conventional temperature logging can usually define degree of intake and outflow along with change in fluid phase as a result of change in temperature. In combination of these implications, downhole flow contribution and injection profile can certainly be determined even though fluid moving in and out through production tubing and casing.
Regarding pilot field implemtation in Sirikit field, two multi-zone-completed candidates have been selected, operations were carried-out for producer and injector according to the programs individually designed including logging across perforation intervals and station stops for multi-rate flow, transient and shut-in periods. Longer well stabilization is necessary for injector. In addition to production/injection logging interpretation by incorporating pressure, temperature, density and spinner data, the temperature simulation model is generated to determine downhole flowing/injecting contribution with parameters acquired during logging, for example, pressure and temperature. The other reservoir and fluid properties, e.g. permeability, thickness, hydrocarbon saturation, skin, heat conductivity and capacity have been analog based on available data from neighboring areas. Therefore, the historical data on production and injection including nearby well performance may be crucial to define necessary input to the model. In association with the interpretation of noise logging which is utilized in locating contributing/injecting zones, the interpretation strongly relies on acquired temperature data and outputs of temperature simulation model to match with measured temperature profile. However, limitations have been documented when dealing with multi-phase flow, especially in low flow rate condition – considered 5 BPD as a threshold. Sensitivity run with associated paramenters in the interpretation can significantly reduce the number of uncertainties to match with measured temperature profile.
Temperature and Spectral Noise Logging to provide input to temperature model can definitely help accessing downhole injection profile for the injector by taking benefit of one phase injecting and having contrast between injecting fluid and geothermal temperatures. This application can significantly improve the waterflood performance and optimization particularly in high vertical heterogeneous reservoirs – thief zones can be identified and shut-off consequently. However, defining downhole contribution for low-rate oil wells producing from multi-layered depleted reservoirs especially in undersaturated condition is still a challenge.
Horizontal wells are being a common practice in offshore field development in Bohai Bay recently. Maintaining well trajectory in sweep spot while drilling is one of the key factors to optimize horizontal well’s productivity. However, great challenges are often faced in Bohai Bay area including survey uncertainties while drilling and reservoir geology variation. On the one hand, successful placement of a horizontal well requires accurate landing of the well in the right position and orientation in the reservoir. On the other hand, the trajectory is optimized based on structural geobody variation resulted from the uncertainty of parameters governing the static behavior of the field. Therefore, the ability to update geosteering model in timely manner and to proactively adjust well trajectory in real time are required.
This paper presents an innovative method in Bohai Bay by applying the technology of integrated seismic volume and reservoir geosteering model while drilling to achieve very promising productivity. That is to say, the new geosteering method includes seismic inversion of checkshot calibrating, single/multi-wells reservoir model updating, conventional logging while drilling, and mud logging etc. How to develop new horizontal well steering methodology and software integrated seismic volume of time (or depth) domain, logging while drilling, reservoir modeling result to optimize well planning and placement for high productivity?
Results from lower Neogene Minghuazhen formation tests executed in SuiZhong 36-1, Bozhong oilfield of Bohai Bay clearly demonstrate the following capabilities of the technology. Reduction of the steering need for the tools of distance to boundary included Directional and deep well placement tool. A bridge from three-dimensional geology model to two-dimensional geosteering model before drilling; vice versa, 2D geosteering model update 3D geological model after drilling.
Reduction of the steering need for the tools of distance to boundary included Directional and deep well placement tool.
A bridge from three-dimensional geology model to two-dimensional geosteering model before drilling; vice versa, 2D geosteering model update 3D geological model after drilling.
More People grasp the systematical methodology of integrated reservoir geosteering model and trajectory optimizing while drilling which provide a higher degree of confidence in the drilling process.
In the past decades, a large amount of oil production in White Tiger oil field was from basement reservoir. However, in recent years, these pay zones consist of basement reservoir, Oligocene reservoir and Miocene reservoir of which oil field have been declined of oil production rate. One of the huge issues in the basement reservoir face is that water cut is significantly increased during oil production yearly. Therefore, the total amount of oil production in all pay zones sharply decreased with time period. At present, the lower Miocene reservoir is the one of the best tight oil reservoirs in order to produce oil production. The lower Miocene reservoir has been faced some issues such as high heterogeneity, complex structure, catastrophic clay swelling, low connectivity among the fractures, low effective well bore radius and the reservoir that is high temperature up to 120°C, the closure pressure up to 6680psi, reservoir pressure up to 4500 psi, reservoir depth up to 3000m. Another negatively conductivity consists of both low reservoir porosity ranging from 1% of the hard shale to 10% of the sandstone formation, and the low permeability raining from 1md to 10md. By considering the various recovery methods, the integrated hydraulic fracturing stimulation is the best tool to stimulate successfully this reservoir, which method actually allows an increase in oil production rate. In the post fractured well has been shown an increase in the productivity over 3 folds in comparison with the base case with fracture half-length nearly 75m, and fracture conductivity about 5400md.ft, which production rate is higher than the production rate of the base case. In addition, the proppant mass is used of 133,067 lbs of which the first big stage is to pump sinter lite bauxite proppant type of 20/40 into the fractures and the next big stage is to pump sintered ball bauxite proppant size of 16/30 into the fractures, which not only isolate proppant flow back but also increase fracture conductivity at the near wellbore as wel as high productivity rate after fractured well. To improve proppant transport, fracturing fluid systems consist of Guar polymer concentration of 11.2 pptg with these additives to form total leak-off coefficient of 0.00227 ft/min0.5.
Choodesh, Attawit (PTTEP International Limited Yangon Branch) | Graham Grant, Colin William (PTTEP International Limited Yangon Branch) | Wuthicharn, Katha (PTTEP International Limited Yangon Branch) | Ramirez, Cristian (Halliburton) | Nusyirwan, Ahmad (Halliburton) | Santoso, Doffie Cahyanto (Halliburton)
Typical sand-control treatments applied in this field are high-rate water packs (HRWPs) or fracture for placement of proppant (FPP). In many cases, the use of a pad is necessary to maximize the amount of proppant placed into the formation and help reduce (bypass) overall skin using onsite data analysis. The gravel pack carrier fluid is a viscosified system with shear-thinning rheological properties and efficiently suspends sand in static conditions. Additionally, this fluid allows substantial flexibility in sand control design for varying degrees of sand support for gravel packing, fluid-loss control, friction-pressure reduction, and a low-damage fluid system (validated with extensive laboratory testing using reservoir cores with carrier fluid to validate returned permeability values).
The objective of the relative permeability modifier (RPM) in sand-control chemical treatments is to prolong hydrocarbon production over time with effective control of water production in one step as a prepad fluid, eliminating the cost and complexity of the water-shutoff treatment stage later as part of well life.
Applying the RPM process has not only reduced water production in these areas, but it has also resulted in more gas cumulative production. It is also important to monitor production for several months after the treatment to determine the success or failure of the application.
Globally, this is the first successful application of RPM delivery in the same aqueous gravel-packing carrier fluid system using a pad fluid consisting of high-grade xanthan polymer as a gelling agent. Implementation of this process provides the operator an additional tool to increase the possibility of hydrocarbon production from a reservoir that has not been considered viable. Use of RPM technique in sand-control completions provides the option to treat wells and control water production resulting from nearby GWC after sand-control treatments.
Razak, M. Firdaus B. (PETRONAS) | Khalid, Aizuddin (PETRONAS) | Sapian, Nik Fazril Ain (PETRONAS) | Madzidah, Asba (PETRONAS) | Samuel, Orient Balbir (PETRONAS) | Khalid, M. Zaidan B. (PETRONAS) | Mohd, Shamsulbahri B. (PETRONAS) | Bakar, M. Farris (PETRONAS) | Salih, Mohamed Sharief Saeed (PETRONAS) | Ruvalcaba, Jazael Ballina (PETRONAS) | Sadan, Nur Syazana (PETRONAS) | Misron, M. Al-Perdaus B. (PETRONAS) | Afzan, A. Satar (PETRONAS) | Jamal, Ajmal Faliq B. (PETRONAS) | A'akif, Nurul Aula bt (PETRONAS) | Mohr, Ludovic (PETRONAS) | Tajuddin, Nor Baizurah bt Ahmad (PETRONAS) | Kalidas, Sanggeetha (SCHLUMBERGER) | Faizah, P. Mosar Nur (SCHLUMBERGER) | Goh, Gordon (SCHLUMBERGER) | Tan, Tina (SCHLUMBERGER) | Palanisamy, Ravishankar (SCHLUMBERGER) | Luke, Darren (SCHLUMBERGER)
The ‘B’ Field is located about 40 KM, offshore Sarawak and was discovered in 1967 with 70-80 m water depth. Structurally, ‘B’ field is charaterised by a simple relatively flat, low-relief domal anticline which is bounded to the north and south by the north-hading growth faults. The major faults are acted as effective lateral seal, which is indicated by the difference in the fluid type and fluid contacts across those faults. ‘B’ field consist of multiple hetereogenous sandstone reservoirs with permeability and porosity ranging from 25 −1700 mD and 16 −29% respectively.
‘B’ Field injectivity conformance for reservoir pressure support is very crucial as the field is undergoing severe depletions over years and unable to meet the production target. The Operator realized the importance in order to further increase the recovery factor, hence has included ‘B’ field in the Improved Oil Recovery (IOR) project to boost the production and prolong ‘B'field's life. Based on comprehensive IOR/EOR screening study, water injection process has been identified as the most amenable IOR process in ‘B'field. Hence, in Phase 1 drilling campaign, two (2) water injectors were drilled in 2016 in order to achieve the target oil recovery. Both well BWI-01 and BWI-02 were completed with Intelligent completions (IC) and expected to come online in Q4 2018.
This paper further discusses the injection strategy in ‘B’ field multi-zones to meet the zonal injectivity and reservoir zonal voidage replacement requirement for pressure maintenance over field production life. The discussion covers the reservoir characteristics and zonal injectivity challenges with surface constraints that require intelligent completions solution for IOR phase. Completions architecture and customized metallurgy needs is crucial to meet operational challenges. Fit-for-purpose and maintaning development cost is pre-requisite to achieve well injection performance for optimal production
Wang, Wei (CNPC-DaQing) | Zhao, Yuwu (CNPC-DaQing) | Xue, Huizhi (CNPC-DaQing) | Wang, Huijun (CNPC-DaQing) | Chen, Jing (CNPC-DaQing) | Wang, Fei (Schlumberger) | Fu, Zairong (Schlumberger) | Li, Cang (Schlumberger) | Chen, Chengqian (Schlumberger) | Wang, Shuai (Schlumberger) | Yuan, Xiangwei (HOPEC)
Tight oil filed A located in Songliao Basin North China has been producing for over 15 years. During Phase I, most of primary production came from vertical/directional wells with fracturing operation, the average production is 0.3 ton per well at the end of 2012 and only 8.78% oil recovery is recorded. This marginal oilfield stepped in to Phase II with a horizontal drilling campaign to increase final recovery rate.
The length of planned horizontal section more than 1500m for single well within extra thin tight reservoir (around 1.5m TST). Meanwhile, the budget is very limited during down turn. The drilling efficiency is the most crucial element to ensure the success for this project. Servals challenges was identified during pre-drilling assessment:
Dogleg severity(DLS) in this extra thin laminated reservoir is very unstable base on previous drilling practices Ensure smoothly trajectory control within such narrow geosteering window with high rate of penetrate(ROP)
Dogleg severity(DLS) in this extra thin laminated reservoir is very unstable base on previous drilling practices
Ensure smoothly trajectory control within such narrow geosteering window with high rate of penetrate(ROP)
To overcome above challenges, an integrated solution was developed implemented to this drilling campaign:
Fit for purpose rotary steering system (RSS) was tested including the point-the-bit RSS and push-the bit in this project and found the best solution to ensure efficiency DLS finally. A boundary mapper LWD tool with ability to map multiple key boundaries, this method not only support proactive geosteering to keep trajectory within narrow geosteering window and avoid unnecessary adjustment, out of target or sidetrack, but also can help to keep the trajectory within fast ROP zone during real-time operation.
Fit for purpose rotary steering system (RSS) was tested including the point-the-bit RSS and push-the bit in this project and found the best solution to ensure efficiency DLS finally.
A boundary mapper LWD tool with ability to map multiple key boundaries, this method not only support proactive geosteering to keep trajectory within narrow geosteering window and avoid unnecessary adjustment, out of target or sidetrack, but also can help to keep the trajectory within fast ROP zone during real-time operation.
Two typical wells were completed successfully. Outstanding outcomes have been observed by implementing this integrated approach in the complex target reservoirs. The drilling efficiency was improved by 38.7%~132.6% with smoothly trajectory control. The complex structure was identified clearly and the average Net to Gross (NTG) more that 97.5%, and the production reached to 18ton/day which far exceeding expectation.
The successfully application of the integrated solution in extra thin reservoir tight oil field will lead to improve drilling efficiency and save budget, increasing the production and well economics. We believe this approach and technique could address another similar formation development.
Zhang, Ruxin (State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development, and State Key Laboratory of Petroleum Resources and Engineering, China University of Petroleum) | Hou, Bing (State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development, and State Key Laboratory of Petroleum Resources and Engineering, China University of Petroleum) | Zeng, Yijin (State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development, Sinopec Research Institute of Petroleum Engineering) | Zhou, Jian (State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development, Sinopec Research Institute of Petroleum Engineering) | Li, Qingyang (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University)
Traditional hydraulic fracturing requires lots of water and sand resulting in short fracture length and small SRV with a low production. However, a new waterless fracturing, called Liquefied Petroleum Gas (LPG) fracturing, is applied to stimulate shale formation effectively.
In order to figure out the mechanism of fracture initiation and propagation in LPG fracturing, four large-scale true tri-axial fracturing simulation experiments have been conducted on shale outcrops. Meanwhile, the effects of engineering factors, pump rate and fluid viscosity, on fracture propagation behavior in the shale formation are discussed.
The experimental results indicate that LPG fracturing not only activates discontinuities to form a complex fracture network, but also enhances induced fracture length to form a large SRV. Induced fractures have two initiation points, open-hole section and stress concentration point of wellbore wall, and have three main propagation behaviors, crossing, shear and arrest, dilation and crossing in shale formation. A low viscosity fracturing fluid activates discontinuities resulting in complex fractures, whereas, a high viscosity fluid would like to create some main fractures without opening discontinuities. Moreover, a high pump rate offers more energy for induced fractures to cross the discontinuities resulting in a long fracture length and large SRV. In addition, the anisotropic of shale formation and the existence of discontinuities cause signals attenuation, which increases the arrival time, resulting in location deviation of acoustic emission (AE) events in the AE monitoring. The pressure-time-energy curve, however, shows that the fracture initiation is earlier than the sample ruptured. That is, the initiation pressure is smaller than the ruptured pressure.
The experiments conducted in this paper prove that the LPG fracturing indeed has some advantages than traditional hydraulic fracturing, such as long fracture length and large SRV. And then, the research results provide the theoretical basis for the LPG fracturing operation in shale formation.
Abdila, Sayid Faisal (SKK Migas) | Harahap, Andy Mahyuni (Pertamina EP) | Yuristyanto, Haryo (Pertamina EP) | Muslim, Aziz (Pertamina EP) | Noviasta, Bonar (Schlumberger) | Falhum, Hanafi Muhamad (Schlumberger) | Astasari, Kanya (Schlumberger)
The Louise (LSE) is one of the primary oil-producing fields in the Pertamina EP Asset V. This area has an issue with high potential of total losses in the top section [~400 m measured depth (MD)], which causes an inability to set the 13.375-in. casing at the required depth. As a result, this problematic zone must be drilled conventionally in two different sections, 17.5 in. and 12 .25 in., whilst combating losses. Pertamina EP spent up to 10 days as nonproductive time (NPT) to combat losses, resulting in high investment cost. A new innovative method was required to face this challenge with the objective of drilling deeper through the loss zone in a single run in a more effective and efficient and a safer way.
Nondirectional casing drilling technology was introduced to solve this problem. The casing drilling system simultaneously drills and runs the casing through the lost circulation zone in a single run, which provides a more efficient and a safer operation. Its plastering effect helps strengthen the wellbore by smearing cuttings into the wellbore wall, sealing pores in the formation to reduce fluid loss. At the same time, it saves the rig operating days by eliminating the loss-combating days and the dedicated casing run. The key driver of this technology is the drillable alloy casing bit specially made for drilling vertical or tangential wells, which can be drilled out by any standard PDC or milled tooth after it has drilled to total depth (TD) and the casing has been cemented in place.
On the pilot casing drilling project well, this system successfully drilled 351.25 m of 13.375-in. × 17.5-in. section to the casing point in a single run passing through the problematic loss zone. The 13.375-in. casing was cemented in place, and the casing bit was successfully drilled out using a conventional 12.25-in. PDC bit. Compared to the conventionally drilled offset wells, this technology enabled up to 220 m deeper 13.375-in. casing setting depth, which consequently eliminated the necessity of loss-combating activity in the 12.25-in. hole section.
The implementation of the casing drilling system solved the lost circulation problem and provided an additional benefit of eliminating a dedicated casing run. The casing drilling technology helped Pertamina EP to reduce the well drilling time by up to 4.75 operating days, saved up to USD 555,913 of drilling cost, and achieved 50 m deeper well TD compared to the plan. The pre-execution engineering work was one of the key activities leading to the success.
An attempt has been made in this work to formulate a novel water based mud system with acrylamido-methyl-propane sulfonate polymer (AMPS) grafted clay/CuO nanocomposite for drilling the high temperature troublesome shale formations. Literature survey found several water mud applications of AMPS polymers in the high temperature and high salinity environment as they are highly water-soluble anionic additives. On the other hand, investigators have reported very encouraging results on rheology and fluid loss control, shale impact, well bore stability and strengthening, cuttings lifting capacity and suspension and impact on thermal properties with CuO nano particle. The improvement in rheological and fluid loss control can be attributed to the fact that pore size studies on shales have suggested nano pore size of 2-50 nm. Conventional shale stabilizers and polymers contained in a water based mud cannot plug nanopores of shale. Therefore, water invades into the wellbore, and results in high mud filtrate volume and clay swelling. Given above, AMPS grafted clay/CuO nanocomposite is expected to improve on the CuO nano particle (NP) performance and provide an excellent solution to plug nano pore size of the shale. Hence, in this paper we tried to develop a synthesized additive which assists the drilling mud to provide better bore hole stability and well integrity while drilling the formations.
Sand and fines production in oil and gas wells are a major challenge that can result in production system failures. In unconsolidated sand reservoirs, proper sand-control practices are necessary to help prevent reservoir sand production. To remove formation damage and control fines migration, acid treatments are pumped ahead of sand-control treatments, which can be challenging because variations in mineralogy determine fluid performance and require a customized fluid selection. For this case, improvements in cased hole sand-control completions were initially sought by switching to high-rate water pack (HRWP) or fracture for placement of gravel (FPG) techniques; however, obtaining fracture conductivity and minimizing out-of-zone fracture growth was challenging. To accomplish the latter, fluid selection was optimized with linear-gel systems and relative permeability modifiers as prepad systems. Operators should know the formation's composition at the treatment point for a successful acidizing treatment to be performed. The dominant mineral component and temperature of the target formation determines the most effective preflush, hydrofluoric (HF)/hydrochloric (HCl) acid treatment blend, and preflush/treatment volume.
The successful implementation of HRWP and FPG techniques produced excellent results with regards to skin minimization and production maximization. The HRWP technique was applied when gas/water contact was nearby, allowing flow from a moderate to high payzone kh (permeability × net pay), and FPG was used to produce a proper flow in low kh formations.
The goal of sandstone-matrix acidizing is to remove siliceous microparticles blocking or bridging pore throats by injecting acid formulations containing HF acid. The presence of potassium feldspars, sodium feldspars, illite, and zeolites is a concern because these compounds can form or contribute to forming significant matrix-blocking precipitates, such as sodium or potassium fluosilicates and aluminum fluorides, during HF/HCl treatments. Variations in mineralogy determine fluid performance and make customized fluid selection necessary. The goal is to minimize the risk of over acidizing the near-wellbore region and to extend the reaction for deeper penetration when possible. In some cases, the acid systems with the equivalent strength of up to 1.5% HF acid were used.
This paper describes the planning process, acid treatment selection based on laboratory testing, placement and diversion techniques, sand-control completions selection, operation summary, and evaluation of treatment success.