|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
Africa (Sub-Sahara) Sonangol's deepwater Orca-1 well encountered oil in the presalt layer of Block 20/11 in the Cuanza basin offshore Angola. The well reached a measured depth of 12,703 ft. Initial well tests saw flow rates of 16.3 MMcm/D of gas and 3,700 BOPD. Cobalt International Energy (40%) is the operator, with partners Sonangol Research and Production (30%) and BP Exploration Angola (30%). Asia Pacific Premier Oil's Kuda Laut-1 well in Indonesia's Tuna production sharing contract has encountered 183 net ft of oil-bearing reservoir and 327 net ft of gas-bearing reservoir. Following evaluation operations, the well will be sidetracked to drill the Singa Laut prospect in an adjacent fault block. Premier is the operator (65%), with partner Mitsui Oil Exploration Company (35%).
The main objective of this research is to present two new approaches for unconventional gas reservoirs rock typing methods. In our rock typing we automatically adjust rock type classes by optimization routines using specific surface area per unit grain volume and volume of kerogen values. Further, our results are compared to other conventional rock typing methods. The presented methos can enhance unconventional reservoir characterization by developing and/or establishing new correlations. This is exemplified through a real case study of an unconventional shale gas reservoir called Upper Safa formation that is located in the western desert of Egypt. Addition we describe the fluid properties more consistently through a full integration of unconventional rock parameters such as surface roughness factor, gas adsorption, type of kerogen, volume of kerogen, level of maturity and total organic carbon content.
The Upper Safa formation is a shale gas unconventional resource play. Interpretation analysis has confirmed the hydrocarbon potential in the Upper Safa formation. Geochemical pyrolysis analysis has been used to confirm the presents of Kerogen type III. Total organic carbon content results are obtained within the ranges of very good petroleum potential according to Rock Eval pyrolysis from 2% to 4% TOC.
The Upper Safa formation is a highly heterogeneous formation, with the Dykstra Parson permeability variation giving a heterogeneity value close to 100%. Large variation in the permeability, rangeing from milli-Darcy to nano-Darcy, is common for unconventional shale reservoirs. This large variation in permeability complicates rock typing of the reservoar. Several conventional rock typing methods have been applied to for the zonation problem, including as Amaefule, Discrete rock typing, Flow Zone Indicator, permeability predictive model, Winland, and a modified Winland. For comparison of the different methods, they have all been forced to produce the same number of rock classes. We have established routines for optimal selection of the boundary values distinguishing these rock classes. We also present two new rock typing techniques utilizing specific surface area per unit grain volume and TOC values.
Sonangol's deepwater Orca-1 well encountered oil in the presalt layer of Block 20/11 in the Cuanza basin offshore Angola. The well reached a measured depth of 12,703 ft. Initial well tests saw flow rates of 16.3 MMcm/D of gas and 3,700 BOPD. Cobalt International Energy (40%) is the operator, with partners Sonangol Research and Production (30%) and BP Exploration Angola (30%). Premier Oil's Kuda Laut-1 well in Indonesia's Tuna production sharing contract has encountered 183 net ft of oil-bearing reservoir and 327 net ft of gas-bearing reservoir.
A multiyear study of water wells in rural An author of the report, Amy earliest days of unconventional development areas during intensive development in Townsend-Small, director of environmental in those counties, allowing them to the Utica Shale found that some had studies and associate professor establish base levels of gas and observe high levels of methane (CH 4), but chemical at University of Cincinnati, cautioned any changes over time. They collected testing showed that was not the that "this study represents a very small from 2-8 samples over time from 24 source of that gas. Those represented 118 of the 180 Based on the carbon isotopes identified small geographic area" compared with samples tested. in the well water samples collected the huge scales of unconventional development. "We did not see an increase in CH 4 by researchers, the methane was from Other studies have concluded concentration or change in the isotopic shallower depths. This biogenic gas was that groundwater was affected by fracturing, composition of CH 4 in groundwater likely produced by bacteria in places but have not combined testing in regularly monitored wells over the like the soil and in coal seams, according from the start of development and isotope study period despite a large increase to the study in the June 2018 issue of identification. In fact, we saw a and Assessment. in three locations that "had CH 4 levels decrease" in some regularly monitored There are "production-scale coalbed posing a fire or exploration hazard wells, the study said.
Egypt's Western Desert reservoirs are characterized to be tight clastic reservoir. In the early development stages only layers with high permeability were produced while tight formation was not considered economic due to application of conventional completion strategy resulting in very low production results. With the decline of Egypt's hydrocarbon production and increase in domestic demand of energy, economically production from these tight reservoirs is a great challenge to maintain production's annual decline. The prospective of these tight producing zones were discovered at a depth below 14,000 feet where the stress is extremely high (1.1 psi/ft) and the reservoir permeability conditions are low with range of 0.2 mD; being necessary in all cases to fracture stimulate each horizon to define the fluid and evaluate productivity. The extreme stress condition and high fracturing treating pressure, risk of premature screen out are one of the main challenges to perform fracture stimulations on these formations which exceeded the working capability of the available equipment in addition; it required significant amount of horsepower on location. Initially, the conventional fracturing treatment was conservatively designed in terms of treatment rate, polymer loading of fracturing fluid and proppant concentration to manage both risk and treatment proppant placement. However, this conservative approach impaired proppant-pack conductivity and the effectiveness of the fracture half-length However, premature screen-outs severely disrupted stimulation operations, leading to costly nonproductive time and deferred production. The poor results using these conventional fracturing techniques during initial exploration and development, the wells were deemed uneconomical. The recent advances in channel fracturing technology; enabled operators to unlock the potential of their toughest reservoirs to economically produce and unlock the enormous amount of hydrocarbons retained in the rock, prolong life of mature fields and achieve production targets. With the application of this technique, helps alleviate the risks of screenout and mitigates the proppant bridging buildup, as the proppant is added in pulses along with dissolvable fibers. These proppant pillars are suspended and held in place by fibers during the treatment. Once pumping is stopped, the fracture closes on the proppant pillars and the fibers degrades under effect of formation temperature. These pillars hold stable channels along the entire geometry of the fracture that provide open pathway for hydrocarbons to flow in near-infinite conductivity. Additionally, 40% less proppant was used and reducing pump rates, which lowered horsepower requirements by 30%. Results indicate that the channel fracturing technique has significantly impacted wells' performance and achieved the desired objectives over conventional fracturing methodologies. Positive features that were observed such as reduced net pressure increase estimates, elimination of near-wellbore screen-outs.
Experience gained in recent activity in the Levantine basin has allowed for the development of a formation evaluation strategy for accurate reservoirs description in this region. The proposed evaluation approach considers operational issues of deep water wells, challenging borehole conditions (high salinity mud, deep invasion) and other geological features of these clastic reservoirs and their fluids.
Our case study highlights benefits of the integrated evaluation of new laterolog resistivity data together with 2D NMR inversion results optimized for a gas bearing reservoir. Furthermore borehole imaging logs are included in our evaluation approach.
The recently developed multi laterolog tool has an advantage of four multiple depths of investigation. It provides a detailed high 1ft vertical resolution radial resistivity profile overcoming the deep invasion often present in these reservoirs. The NMR acquired in gas oriented acquisition mode exploits the multi-frequency capability of the logging device. Combined together multiple G•TE and multiple TW experiments contribute to robust determination of the T1 and T2 reservoir fluid properties. This acquisition sequence allows for continuous hydrocarbon typing applying the T1/T2 vs T2 2D maps method, which is practical for these reservoirs given the T1 contrast between gas and other fluids. Consequently we are able to perform accurate HI corrections and therefore improve the estimates of NMR permeability and saturations. Further in the workflow we compare NMR and Stoneley wave permeability’s and assess in details their differences.
The geological study performed with the combination of simultaneously acquired ultrasonic and resistivity borehole images provides additional insight into the reservoir architectures, taking advantage during the analysis of the different logging responses of the petrophysical factors to acoustic and resistivity investigation for a detailed delineation of the productive beds.
The advantages of this integrated approach are illustrated with field data examples.
In Egypt's Western Desert, the Alam El-Buieb formation (AEB) and the Safa reservoirs have remained a challenge to drill because of their high compressive strengths and abrasive sandstone/siltstone formations. In the AEB and Safa formations, vertical sections are drilled regularly using several 8½-in roller-cone tungsten carbide insert (TCI) bits. To improve section performance and reduce overall cost per foot ($/ft), impregnated bits run on turbines and high speed motors were initially used. While these types of bottom hole assemblies (BHA) had advantages, they also came with disadvantages: The high-running costs and greater lost-in-hole (LIH) costs associated with these assemblies was a concern for most operators. Additionally, some rigs lacked the power to run them. These conditions motivated operators and bit suppliers to find alternative assemblies that can successfully drill challenging sections while reducing the $/ft by increasing the ROP and the footage each bit drills.
Recent advancements in polycrystalline diamond compact (PDC) bit design have made this possible. By altering PDC-bit profile, shape, cone angles, back rake angles, cutters and conducting test runs while being guided by finite element analysis (FEA) based modeling system and CFD modeling, design teams have produced PDC bits that are best suited for the targeted application (formation and rotary BHA). In conclusion, the newly designed PDC bits have shown a significant increase in ROP and footage compared to TCI and impregnated bits. The result is a significant reduction in drilling costs running PDC on rotary assemblies.
The need to increase productivity and to reduce drilling damage favors the use of underbalanced drilling (UBD) technology. In highly depleted reservoirs, extremely low-density fluids, such as foams or aerated mud, are used to achieve circulating densities lower than the pore pressure. In such cases, the induced modification of the in-situ stresses has to be supported mainly by the rock, with little contribution from the drilling fluid pressure. The application of underbalanced drilling depends on the mechanical stability of the drilled formation, among other factors. In general, poorly consolidated, depleted formations are not suited for that technology.
In this paper, twenty three UBD worldwide cases have been analyzed; two of which are from Egyptian fields and the others are from Iran, Algeria, Kuwait, Oman, Texas, Mexico, Indonesia, Canada, Libya, Middle East, Qatar, Saudi Arabia and Lithuania. From these analyses, the reasons of failure or success have been stated. The reasons of success included depleted reservoirs and highly fractured carbonates formation while, the reasons of failure include overpressurized shale, highly tectonic stress areas, and downhole failures. The main attractive application of this technology was proposed to be only in the reservoir section, and the target was to prevent the reservoir damage and hence increase the productivity and recovery factor.
A proposed underbalanced drilling program is developed based on these analyses to be used in the three main regions in oil and gas producing Egyptian fields. The aerated mud was selected as a drilling fluid to drill the reservoir section in Western Desert and Gulf of Suez region whereas the single phase fluid was selected as a drilling fluid in the Nile Delta region.
Analysis of tight gas sand reservoirs is one of the most difficult problems. Many tight formations are extremely complex, producing from multiple layers with different permeability that is often enhanced by natural fracturing. Therefore, looking for using new well logging techniques like NMR in individual bases or in combination with conventional open hole logs and building new interpretation methodology is essential to well define and obtain the representative reservoir characterizations.
Nuclear magnetic resonance (NMR) logs differ from conventional neutron, density, sonic and resistivity logs because the NMR measurements provide mainly lithology independent detailed porosity and a good evaluation hydrocarbon potential. NMR logs can be used to determine formation permeability and capillary pressure.
This paper concentrates on three petrophysical applications of NMR; 1) present a technical method for porosity calculation in which density and NMR porosities are combined and calibrated to core, 2) Use new empirical method of bulk gas volume (BG) in the invaded zone for permeability estimation termed BGMRK and 3) Use T2 distribution for capillary pressure approximation and correct pore size distribution for gas.
These applications of NMR logs have been applied in a gas sand reservoir field of different facies and permeability varies from less than 0.1md to more than 100md related to facies changes. These applications result in a) The technique of using combined NMR and bulk density data significantly reduces uncertainty in porosity through elimination of the neutron log down to 0.5%. b) The new approach of "BGMRK" resulted in very simple facies independent model to calculate reliable permeability 2. c) Capillary pressure can be approximated from NMR T2 distribution and then the integration between cap-curves and T2 distribution can be corrected for partial pores fluid fill.