Ibrahim, M. Z. (Carigali-PTTEPI Operating Company) | Ibrahim, M. M. (Carigali-PTTEPI Operating Company) | Findlay, C. (Carigali-PTTEPI Operating Company) | Techanukul, T. (Carigali-PTTEPI Operating Company) | Noor Hassim, M. F. (Schlumberger) | Wongyaowarat, K. (Schlumberger) | Ramli, M. R. (Schlumberger)
The recent infill wells of MDE were drilled and completed with the most complicated architecture in CPOC. They were designed with high inclination reaching almost 87 degree and 2.6 ERD ratio in order to optimize hydrocarbon recovery from multi-stacked reservoirs within the area. The study, driven by cost effective initiatives, compared wireline tractor conveyed perforation (run in normal and reverse deployment modes) and coiled tubing conveyed perforation (again, run in normal and reverse deployment modes). The aim of this study is to provide the most efficient technique to achieve maximum hydrocarbon returns with low operational costs and minimum risks. The scope of this study includes consideration of well test requirement and net over gross ratio of perforation interval.
Four (4) options are feasible to complete these high inclination and long departure wells: wireline tractor-conveyed perforation (run in normal and reverse deploy modes); and coiled tubing-conveyed perforation (run in normal and reverse deploy modes). The analysis includes several factors such as different rig-up height, perforation depth accuracy, perforation flexibility, operation time, and tool requirement. Generally, the job executions begin by rigging up the perforating gun into wireline or coiled tubing conveyance, then running in hole to designated target depths.
The wireline tractor with reverse deployment and multiple-firing system was the chosen method, deployed for the first time in slim hole, high inclination and long departure wells within Joint Development Area (JDA), Gulf of Thailand. This conveyance method proved to provide a 68% reduction in numbers of runs, with cost reductions of 25% and 50% in operating day and operating costs respectively. Perforating operations in all three wells were successfully completed with 269 meters total perforation length. The tractor operated for a total distance of 94 kilometers which is considered as the longest tractor marathon in a campaign worldwide.
The utilization of tractors for this campaign is considered as a record breaking for the operators and contractors. As a result, the wells have been able to deliver the gas as expected and fulfill the nomination to buyer demand.
Sampling in a highly deviated well involves additional risks that can compromise efficiency and costs. Operators and service companies have developed options to overcome the technical challenge of going from tubing-assisted logging to tractor-conveyed operations. Tubing-assisted logging will mitigate the issues and stuck risks caused by wireline key seating, differential sticking, swelling formations, heavy muds, borehole breakout, doglegs, ledges, and cuttings but will require slower operations resulting in additional rig time and therefore costs. Tractor conveyance, on the contrary, can be efficient but will add costly operating rates and higher cost exposure if the tools are lost in hole.
Fadjarijanto, A. (Carigali-PTTEPI Operating Company) | Rachmadi, A. (Carigali-PTTEPI Operating Company) | Setiawan, A. S. (Carigali-PTTEPI Operating Company) | Praptono, A. (Halliburton) | Suriyo, K. (Carigali-PTTEPI Operating Company) | Simatupang, M. H. (Carigali-PTTEPI Operating Company) | Pakpahan, O. (Carigali-PTTEPI Operating Company) | Costam, Y. R. (Carigali-PTTEPI Operating Company) | Zakaria, Z. U. (Carigali-PTTEPI Operating Company)
Fluid identification is a key component of formation evaluation and becomes one of the important parameters that underlie economic decisions in field development. The combination of high clay content in the thinly laminated shaly-sand reservoir, together with unknown water salinity, increases the complexity in the accurate quantification of hydrocarbon-bearing reservoirs. The inherent clay distribution affects the log data response of high gamma and low resistivity analyses. Those responses can lead to incorrect interpretations unless other log data responses are considered.
The low resolution of a common oil-based resistivity tool often fails to capture structurally complex, thinly laminated sand-shale formations. The low resistivity response results from high resistivity sand layers suppressed by low resistivity shale layers, which can result in misinterpretations of calculating high water saturation. Observations of other conventional well log data can provide early qualitative identification of the low contrast zone. Data from the Thomas-Stieber method, resistivity anisotropy, and high-resolution micro-imaging are available to reconstruct conventional log data to provide an enhanced vertical resolution for final interpretations.
A field study was performed in the North Malay basin. Geologically, the field has three-way dip closure, bounded by a west-dipping fault to the west. The early evaluation of the DS2-B layer was interpreted as shale zones following a high gamma and low resistivity reading. Further observation of the density, neutron, and shear sonic trend do not provide the same shale indication. The decision was made to run a formation tester tool and to investigate any possible hydrocarbon indication. Real-time fluid identification and sampling proved the DS2-B layer to be gas-bearing and indicated that the conventional petrophysics-calculated water saturation was too high. Three petrophysics re-evaluation approaches were performed to define the reservoir challenges, including deterministic, Rv/Rh methods, and high-resolution data approach to obtain a better definition. All available data were used on the methodologies, based on the data required for each method, particularly the use of high-resolution imaging and core data for conventional logs to define the high-resolution of porosity, clay volume, and water saturation. As a result of these analyses, the DS2-B layer was proven to be a pay zone with a lower water saturation, which correlated with the formation sampling and core analysis results. The methodology has a proven capability to identify low contrast zones and can provide better interpretation in the field study through providing more a precise and accurate net-to-gross calculation.
The correlation and calibration of the conventional well log data to high vertical resolution image log, core data, and fluid sampling have provided a means of better visualizing and understanding the features of thinly bedded reservoirs in the field study. All methods were performed to calculate the final fluid saturation in highly laminated reservoirs. The new interpretation has proved a significant contribution to the NM field economic value.
Fadjarijanto, A. (Carigali-PTTEPI Operating Company) | Pakpahan, O. (Carigali-PTTEPI Operating Company) | Kaewtapan, J. (Carigali-PTTEPI Operating Company) | Setiawan, A. S. (Carigali-PTTEPI Operating Company) | Simatupang, M. H. (Carigali-PTTEPI Operating Company) | Rahmadi, A. (Carigali-PTTEPI Operating Company)
This paper presents a novel approach by integrating well log data evaluation to seismic rock physic calibration of field development plans. The result of the study was incorporated in the development drilling to optimizing well placement. To date, the well result demonstrates that the method was proven to determine the gas bearing sand distribution. As a consequence, drilling at a sweet spot location can be optimized.
Reservoir fluid identification is a major role in the formation evaluation task. In the field with multiple stack sands and limited water salinity data, will cause more challenging to define fluid type. The result is very substantial to determine hydrocarbon in place, the volume of which will be used to take the decision to develop the gas field. The inherent uncertainty which comprises of sand and hydrocarbon distribution is a real challenge when identifying the sweet spot location in a development drilling campaign.
Well log data provides essential information that will use for interpretation of lithofacies and fluid type. The elastic acoustic velocity of the formation taken by sonic tool is a common data that are considered in the petropysical evaluation. In essence, the advantage of ratio of sonic compressional to shear wave velocity is applied to identify gas bearing formations. This is based on the fact that compression wave is more sensitive to type of fluids than the shear wave when it travels into the poro-elastic formations. The same method is also relevant when applied to the seismic data. The seismic Vp/Vs ratio must be first calibrated with well data to provide a proper meaning. Thereafter, the seismic Vp/Vs ratio is exerted to determine gas bearing sand distribution. This information is expected to deliver a great contribution in the well placement optimization.
The method is proven to reduce the uncertainty of lateral distribution at shallow reservoirs. The application of this method for deeper reservoir is still being investigated and further detail works will be done to confirm the findings.
Integrated geophysical applications and well datasets play an important role in understanding reservoir distribution and decision making for a robust development plan. A technical assessment was completed in a gas field in the North Malay Basin to describe the reservoir heterogeneity in the Early Miocene to Late Oligocene reservoir intervals. The field is a North-South oriented plunging anticline with stratigraphic trap configuration, discovered in 2007 by Well-X1. The assessment has resulted in a proposal of an appraisal well in 2014, Well-X2ST to delineate the northern hydrocarbon extent and to assess the hydrocarbon potential in the exploration interval of deeper sequences. The new well datasets were acquired and the results were utilized to further evaluate the field.
This paper focuses on the deepest reservoir sequence, DS12, encountered by the appraisal well in the eastern flank of the Malaysia-Thailand Joint Development Area (MTJDA). Rock physics modeling and seismic attribute datasets with well log and pressure data integration were utilized to better understand sand distribution for the upcoming development planning. Due to the thinly bedded nature of the reservoirs, the seismic could not be fully utilized to evaluate internal stacking geometries. This was further complicated by attenuation from the overlying thick shale. However, attribute analysis was effective to determine overall sand presence where the bed thickness ranges from 10 to 15 meters and the seismic detection limit is approximately 8 meters.
Rock property analysis was performed to calibrate both acoustic impedance and Vp/Vs to gamma ray for indication of sand presence. The Vp/Vs derivative was used instead of acoustic impedance because of the extra information obtained in both the elastic and AVO domain. In addition, rock physics modeling was performed to differentiate gas from wet sand and shale. The seismic datasets were used to qualitatively condition a geologic model to better distribute sand presence for well planning optimization. Development wells are planned to target good quality sands to maximize recovery efficiency
The success of proving the deepest reservoir sequence in the eastern flank of MTJDA, utilizing geophysical application and well data integration, have resulted in an improved understanding to outline deep reservoir distribution in the surrounding area and mitigate uncertainties in the development plan.
Adnan, M. Mohd (Carigali-PTTEPI Operating Company) | Ismail, W. Wan (Carigali-PTTEPI Operating Company) | Kaewtapan, J. (Carigali-PTTEPI Operating Company) | Setiawan, A. S (Carigali-PTTEPI Operating Company) | Tanprasat, S. (Carigali-PTTEPI Operating Company)
A comprehensive technical evaluation was conducted after the completion of six exploration and appraisal wells to assess the future petroleum potentials in North Malay Basin, offshore Malaysia-Thailand Joint Development Area (MTJDA). This paper focuses on major discoveries and findings from key wells, namely Well-E3, Well-A2ST, and Well-T3 to better understand the petroleum potentials for the subsequent development planning.
Well-E3 and Well-A2ST were drilled to investigate the stratigraphic trap play in the eastern flank of MTJDA and to explore the hydrocarbon potential in deeper depositional sequence below DS10 interval. The seismic dataset and amplitude analyses were used to identify channel fairways and qualitatively predict sand presence for well planning optimization. Both wells encountered gas-bearing sands with proven stratigraphic trap style, requires channel orientation oblique with the axial anticline structure. Full integration of well log dataset, formation pressure test and seismic attribute analyses have proven the exploration intervals with gas-bearing sands discoveries. In addition, rock physics analysis was performed to differentiate gas from wet sand and coals.
Well-T3 was drilled in the western flank to appraise the seismic anomaly associated with hydrocarbon sand and to investigate the CO2 content in the southernmost extension of hydrocarbon accumulation. The anomaly is observed as two distinct sand fairways of channel-bar complex. The northern lobe was dissected by deep seated fault system with high CO2 content. The southern lobe appears to be free from deep seated fault system. Well-T3 was drilled in the area where CO2 pathways was expected to have no connection with deep seated fault system and lower CO2 content than the main area. Formation pressures, samples and seismic anomaly supported the hypothesis that the northern and southern culminations are not connected with significant stratigraphic heterogeneity interpreted. An important oil discovery was also observed from pressure gradient and samples as the first oil discovery in the western flank.
Full integration of the well log dataset, formation pressures, seismic attribute analyses and rock physics modeling have resulted in an improved understanding of reservoir distribution and reduced the degree of uncertainty in reservoir connectivity, thus allowing a more robust development strategy. The new discoveries of proven stratigraphic trap in the eastern flank with deeper hydrocarbon culminations and proven oil discovery in the western flank with enhanced understanding of CO2 content have triggered more future petroleum potentials in MTJDA acreage.