Devshali, Sagun (Oil and Natural Gas Corporation Ltd.) | Manchalwar, Vinod (Oil and Natural Gas Corporation Ltd.) | Deuri, Budhin (Oil and Natural Gas Corporation Ltd.) | Malhotra, Sanjay Kumar (Oil and Natural Gas Corporation Ltd.) | Prasad, Bulusu V.R.V. (Oil and Natural Gas Corporation Ltd.) | Yadav, Mahendra (Oil and Natural Gas Corporation Ltd.) | Kumar, Avinav (Oil and Natural Gas Corporation Ltd.) | Uniyal, Rishabh (Oil and Natural Gas Corporation Ltd.)
The paper describes the feasibility of revisiting old sands, for improving the recovery factors and enhancing production, which otherwise were already abandoned. The paper also outlines the systematic methods for predicting the onset of liquid loading in gas wells, evaluation of completions for optimization and comparison of various deliquification techniques. ONGC is operating in two gas fields in eastern and western regions in India. Earlier in both the fields, many sands had to be closed/isolated after the wells ceased to flow due to liquid loading in the absence of continuous deliquification. In order to predict liquid loading tendencies and identify opportunities for production enhancement, performance of 150 gas wells has been analyzed. To select most suitable deliquification technique for the present condition, all technically feasible methods have been evaluated and compared in order to get the maximum ultimate gas recovery possible.
After an extensive study, 3 wells were identified in the preliminary stage and SRP was selected as the most suitable Deliquification technique. Initially, two non-flowing wells, which had ceased due to liquid loading and were about to be abandoned, were selected. After SRP installation and sustained unloading of water for about 30 days, these wells started producing 12000 SCMD gas. In the third well, one of the top sands had earlier been isolated due to liquid loading and production history indicated that the isolated sand had a very good potential. Also, production from the well was declining in the current bottom operating sand as well due to liquid loading. Encouraged by the results that deliquification had yielded in the initial two gas wells, the isolated sand interval in the third well was opened again with the aim to revive production. The well was re-completed with SRP with both the reservoirs open. Before deliquification, the well was producing about 15000 SCMD gas from the bottom sand. After SRP installation and continuous deliquification, the well started producing gas at a stabilized rate of 45000 SCMD, thereby resulting in an additional gas recovery of 30000 SCMD for nearly one year as on date. The approach of putting in place continuous deliquification techniques has not only helped in enhancing production from the existing reservoirs, but has also opened up new avenues to revisit the earlier isolated / abandoned reservoirs for possible enhanced recoveries.
S field has unique geological condition, the depth of maturity based on geochemistry analysis start from 800 m and classified as shallow depth rather than in the core of Kutai basin at 4000 m. It was caused by gravity tectonic from north which lifting the middle miocene formation from below. This situation gives the benefit to find source rock in shallower depth for unconventional exploration.
To characterize and predict the source rock especially for Total organic content value is using a well-known method called ΔLog R. This technique has been applied in many field with success stories. Beyond it is success, this method is less recognizing to predict in coal, because of the huge separation between Porosity log and Resistivity log. This study aims to applied this method in delta plain environment with abundant of coal source rock using between Density log, Sonic log, and Neutron log combine with Resistivity log. Besides that, TOC accumulation will be compared with Cyclostratigraphy trend, which trends contain much TOC content and by this vertical distribution to generate lateral correlation.
Basic principle for ΔLog R method is to seek the overlay between porosity log and Resistivity Log. Assuming when TOC is high the sediment rocks has good porosity and higher Resistivity reading. Those are the effect from kerogen in shale and generation of hydrocaron. In immature organic rocks it has good porosity but Resistivity log shows lowest value. Most of organic accumulation is in non reservoir. To eliminate the reservoir zone by using the Gamma ray log. This TOC value will be validate using several geochemistry analyses from cores.
Cyclostratigraphy-INPEFA log, is cyclic deposition that refer to orbital change that effect insolation on earth. This situation cause fluctuates of Eustachy and change the sea level. When sea level drop or N-Trend and coarse sediment will deposit and the other hand P-Trend or warming phase. Predicted TOC accumulation is much higher when warming phase. This trend will help to know TOC distribution around the field.
Guo, Shusheng (CNOOC Ltd_Zhanjiang) | Gao, Yongde (CNOOC Ltd_Zhanjiang) | Gui, Feng (Baker Hughes, a GE Company) | Wang, Shanshan (Baker Hughes, a GE Company) | Bordoloi, Sanjeev (Baker Hughes, a GE Company) | Ong, See Hong (Baker Hughes, a GE Company) | Du, Chao (CNOOC Ltd_Zhanjiang) | Wang, Shiyue (CNOOC Ltd_Zhanjiang)
The drilling in Wushi Sag of the Beibu Gulf appears to be problematic with frequent pack-off, tight-hole and stuck-pipe events as well as kicks and losses occurring in different wells. It is of great importance to find out the main cause or causes of these problems so that proper methods and techniques can be utilized to mitigate the problems and reduce the drilling non-productive time (NPT).
A series of drilled wells were reviewed to identify the key wells to be used for the geomechanical modelling and to help with understanding the drilling problems. One of the outcomes of the detailed geomechanical analysis was the realization that the stresses and rock behaviors are mainly affected and controlled by the structures. Wushi Sag can be divided into four structural areas: subsag-steep slope in the south, central inverted structure area, north slope and strike-slip faulting belt in the west. As a consequence of the complex structures, the formation depth varies greatly while some formations are absent or incomplete in some wells due to the well-developed high-angled faults.
An outcome of the study was the understanding that formation pressures are different in every structural area and are controlled by structural location and burial depth. The main overpressure generating mechanism was found to be type-II fluid expansion caused by either hydrocarbon generation or thermal effects, which can be well correlated to the oil window threshold in the area. Under-compaction may also play a role in some cases, but the overpressure caused by this mechanism is usually low in magnitude. Rock properties vary across the Sag while wells are hard to correlate with each other in different structural areas. The stress conditions appear to be different in each area although the main stress regime is strike-slip with the strike-slip faulting belt in the west having the highest stress ratio.
Due to the complexity of the pressure distribution, lateral formation changes and different stress conditions, improper mud weights and casing designs were used in some earlier wells, which likely led to the types of drilling problems listed above. Wells with severe instability problems were generally drilled with lower mud weights compared to the wells with lesser problems. Wells with both pack-off/tight holes and fluid losses usually have surface or intermittent casing shoes set too shallow while not preparing for the steep pressure ramp in deeper formations. Based on the problem diagnostics and geomechanical analyses, recommendations were made to help with the drilling of future wells by mitigating drilling-related instability problems. A series of wells were drilled successfully following the recommendations with all the possible risks properly understood and mitigated.
The various cycles which affect our oil industry have emphasised the need for detailed control of expenditure for development and production of small discoveries. However, should technical or economic conditions change, such fields may become commercial fields. Marginal fields have several parameters that affect them. This includes environmental concerns, political stability, access, remoteness and, of course, the price and price stability of the produced gas/liquids. This course will describe parts of unconventional methods to develop the marginal fields and mainly focus on innovative methods and new technology in developing those marginal fields.
Saikia, Pabitra (Kuwait Oil Company) | Al-Rashdan, Saad (Kuwait Oil Company) | Taqi, Fatma (Kuwait Oil Company) | Al-Dohaiem, Khalid (Kuwait Oil Company) | Al-Rabah, Abdullah (Kuwait Oil Company) | Tyagi, Aditya (Kuwait Oil Company) | Choudhary, Pradeep (Kuwait Oil Company) | Ahmad, Khalid (Kuwait Oil Company) | Kharghoria, Arun (Kuwait Oil Company) | Malik, Satinder (Shell Kuwait Exploration and Production B.V.) | Zhang, Ian (Shell Kuwait Exploration and Production B.V.) | Cheers, Mike (Shell Kuwait Exploration and Production B.V.)
Free gas along with heavy oil production affects the progressive cavity pump (PCP) performance. This necessitates the strategy to perforate away from the free gas zone. To be able to do this, it requires an integrated approach to evaluate and map the spread of the free gas accumulation in the field. The paper shall present how this resulted in improved well performance with less free gas interference.
The methodology included the understanding of the production data, sub-surface geology and petrophysics; reservoir heterogeneity and free gas presence from wireline logs, core data and isotope analysis of gas collected during mud-logging and creation of maps and cross-sections showing both vertical and aerial spread of free gas accumulation. This was then integrated with existing production and well management practices, along with numerical simulation results. Such in-depth analysis helps to bring significant changes in well completion strategy and is a vital contribution to the WRFM strategy.
Unlike in conventional fields where depth is more and buoyancy pressures are large, gas can easily displace oil to accumulate in structural highs, in shallow heavy oil fields, free gas accumulation is a result of combination of structural and stratigraphic entrapment process. Vertical migration and lateral migration of gas is likely restricted by non-reservoir facies. As a result a consistent gas-oil contact (GOC) may not be present across large distances. Gas oil contact separates heavy oil by possible structural spill point and lithological boundary, dipping from south to north. Structurally higher areas are prone to localized gas accumulation. The completion stand-off from the gas base has a direct correlation with gas production. So the well management and production practice is to increase the stand-off from gas base to top perforations in future wells and to perform gas shut-off job in current wells to avoid free gas production.
The novelty of the current approach is that it will proactively help in completion strategy to reduce future free gas production, subsequent loss in natural reservoir energy and maintain the oil production target.
Primasari, Indah (PT Pertamina Hulu Mahakam) | Wijaya, Geraldie Lukman (PT Pertamina Hulu Mahakam) | Hadi, Aen Nuril (PT Pertamina Hulu Mahakam) | Chendrika, Lusiana (Schlumberger) | Merati, Putu Astari (Schlumberger)
Handil is a mature oil and gas field with dozens of wells drilled within 70-m distance. It has been developed since 1975 and operated by Indonesian national oil company, PT Pertamina Hulu Mahakam. Handil shallow reservoirs are located at depths between 200 and 1500 m true vertical depth (TVD). It has strong aquifer support and unconsolidated permeable sandstone reservoirs with poorly sorted grain size, requiring gravel pack completion. Since 2005, there have been 39 wells completed with gravel pack, contributing 40% of total Handil field production. Handil gravel pack wells are facing productivity impairment; several production tests indicated that 30% of the completed zones have a very low productivity index (less than 0.5 STB/D/psi) after a few years of production.
Organic clay acid (OCA) was proposed as a matrix acidizing technology to dissolve the fines in the critical near-wellbore matrix. For many years, matrix acidizing has been used to remove formation damage or improve productivity in formations containing siliceous clay. The most commonly used treatment fluid is mud acid, which is a mixture of hydrofluoric acid (HF) and hydrochloric acid (HCl). In many conventional mud acid treatments, after an initially good response to the treatment, the production falls to levels similar to those before the treatment; this is thought to be due to the precipitation from the reaction of HF with silica material on feldspar/clay, which results in more hydrated silica gel. Unlike conventional mud acid, OCA can allow a deeper live-acid penetration into the formation and limit possible reaction-product precipitates, which will enhance the effectiveness of the stimulation treatments.
Two OCA trial treatments were executed through coiled tubing. In the first job, the chemicals created an emulsion that was not compatible with fluid on the surface facilities. Demulsifier treatment on the surface successfully diluted the emulsion. Some adjustments on chemical composition have been applied on the second job, which successfully removed the emulsion. The pilot test yielded total oil production up to 900 BOPD (4,000 BLPD) instantaneous gain with ~80% improvement on productivity by reducing skin from >100 to 5. Currently, both wells are still flowing after 6 months of production. Following this success story, more than 11 OCA jobs are planned to improve the productivity of the existing zones in 2018.
A recent matrix acidizing campaign in Handil shallow wells, highlighting the damage verification, candidate selection, acid chemistry, operational constraints, production results, and future opportunities. The logistics which include the flowback of spent acids and acid neutralization in the swamp area, and the addition of demulsifier in surface facilities will also be discussed. There were no core samples available to run a formation response test to the acid prior to the matrix acidizing treatment.
The Sanga-Sanga PSC fields are located onshore Mahakam delta, East Kalimantan, Indonesia. Since the 1970s, they have produced over 80% of originally estimated gas in place with the remaining gas locked up in low permeability sands. A prize of at least 0.75 Tcf would be achievable, if these sub milli-Darcy resources could be developed. However, previous attempts at hydraulic fracturing, over three decades, have been spectacularly ineffective and rarely enjoyed any improvement or uplift at all.
During late 2006, a detailed review of the regional stress-state and prior unsuccessful frac operations was performed. This review unearthed significant evidence of a reverse stress-ordering in the deep low permeability sands, resulting in horizontal fractures being created. While this provided some logic behind the widespread failure rate, it did not in itself offer a direct solution. However, there was also sufficient evidence from previous frac history, to indicate that the solution may lie with a pore-pressure reduction. A pilot program, with meticulous candidate selection was planned to investigate this.
Further investigation determined the presence of a strong poro-elastic relationship and it was assessed that when combined with longevity of production (30 years), that the stress-state would be substantially affected. During 2008, a suite of well candidates were carefully selected with a range of reduced pore- pressures, aligned with the poro-elastic understanding, hydraulic frac treatments were performed and the wells flowed and produced for two years to confirm productivity. The subsequent production behaviour, confirmed a very positive response and the treated wells netted substantial gas/condensate sales. Production behaviour confirmed the poro-elastic relationships and a set of absolute guidelines on candidate selection and fracture execution were created. Subsequent operations that have adhered to these strict guidelines have been extremely successful. The ability of the new approach to reverse a 30- year trend of hydraulic fracturing failure will now lead to the development of the remaining resource within the fields. An extensive treatment campaign will now be possible to perform with between 50 - 100 candidates well opportunities likely to be available in the field.
A careful assessment of the regional stress-state indicated a reverse ordering of the principal stresses as being the root cause of the poor hydraulic fracturing behaviour. However, careful consideration of the rock mechanics and a coherent pilot programme demonstrated the ability, under effective depletion conditions, to place economic and successful hydraulic fracturing treatments.
We devise a workflow to model the pore pressure increase in organic shale to better characterize the shale reservoirs. In particular, the proposed model considers the microstructure in organic shale and the volume fraction variations of rock components during the maturation. The pore pressure increase is solved based on the compressibility and volumes of pore space and pore fluids. Our modeling results agree that the evolution of organic shale’s rock-physics property during kerogen maturation is consistent with fluid expansion model that sonic velocity decrease while density changes little when unloading occurs.
Presentation Date: Wednesday, October 17, 2018
Start Time: 8:30:00 AM
Location: 202A (Anaheim Convention Center)
Presentation Type: Oral
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.